Indiana Michigan Power 10-Q 28 Apr 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 27, 2017
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		491,712,071
Appalachian Power Co [Member]
Entity Registrant Name	APPALACHIAN POWER CO
Entity Central Index Key	6,879
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		13,499,500
Indiana Michigan Power Co [Member]
Entity Registrant Name	INDIANA MICHIGAN POWER CO
Entity Central Index Key	50,172
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,400,000
Ohio Power Co [Member]
Entity Registrant Name	OHIO POWER CO
Entity Central Index Key	73,986
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		27,952,473
Public Service Co Of Oklahoma [Member]
Entity Registrant Name	PUBLIC SERVICE CO OF OKLAHOMA
Entity Central Index Key	81,027
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		9,013,000
Southwestern Electric Power Co [Member]
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER CO
Entity Central Index Key	92,487
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		7,536,640

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
Vertically Integrated Utilities	$ 2,269.8	$ 2,218.1
Transmission and Distribution Utilities	1,066.4	1,077.3
Generation & Marketing	558.8	713.9
Other Revenues	38.3	35.6
TOTAL REVENUES	3,933.3	4,044.9
Expenses
Fuel and Other Consumables Used for Electric Generation	635.6	675.6
Purchased Electricity for Resale	769.6	731.4
Other Operation	602.2	715.1
Maintenance	302.4	278.7
Other Asset Impairment Charges	11.2	0
Gain on Sale of Merchant Generation Assets	(226.5)	0
Depreciation and Amortization	481.9	497.1
Taxes Other Than Income Taxes	259.8	254.1
TOTAL EXPENSES	2,836.2	3,152
Operating Income (Loss)	1,097.1	892.9
Other Income (Expense):
Interest and Investment Income	8	2.1
Carrying Costs Income	5.9	3.9
Allowance for Equity Funds Used During Construction	21.2	31.7
Interest Expense	(221.8)	(217)
INCOME BEFORE INCOME TAX EXPENSE	910.4	713.6
Income Tax Expense (Credit)	343.2	235.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries	27	25
Net Income (Loss)	594.2	503.1
Net Income Attributable to Noncontrolling Interests	2	1.9
Earnings Attributable to Common Shareholders	$ 592.2	$ 501.2
Earnings Per Share
Weighted Average Number of Basic AEP Common Shares Outstanding	491,712,042	491,108,392
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$ 1.20	$ 1.02
Weighted Average Number of Diluted AEP Common Shares Outstanding	492,031,975	491,332,305
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	$ 1.20	$ 1.02
Common Stock, Dividends, Per Share, Declared	$ 0.59	$ 0.56
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	$ 745	$ 775.5
Sales to AEP Affiliates	42.4	40.4
Other Revenues	5.4	4.1
TOTAL REVENUES	792.8	820
Expenses
Fuel and Other Consumables Used for Electric Generation	167.2	150.7
Purchased Electricity for Resale	90.8	108.2
Other Operation	112.6	120.6
Maintenance	71.2	69.3
Depreciation and Amortization	100.6	95.5
Taxes Other Than Income Taxes	30.2	31.3
TOTAL EXPENSES	572.6	575.6
Operating Income (Loss)	220.2	244.4
Other Income (Expense):
Allowance for Equity Funds Used During Construction	1.5	2.3
Other Income	2.1	1.8
Interest Expense	(48.1)	(47)
INCOME BEFORE INCOME TAX EXPENSE	174.2	199.2
Income Tax Expense (Credit)	63.6	72.9
Net Income (Loss)	110.6	126.3
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	538.5	500.4
Sales to AEP Affiliates	0.6	11.5
Other Revenues - Affiliated	18.1	15.3
Other Revenues	3.3	5.5
TOTAL REVENUES	560.5	532.7
Expenses
Fuel and Other Consumables Used for Electric Generation	90.7	69.2
Purchased Electricity for Resale	37.3	49.6
Purchased Electricity from AEP Affiliates	53.9	45.4
Other Operation	135.6	141.3
Maintenance	51.4	40.9
Depreciation and Amortization	50	47.1
Taxes Other Than Income Taxes	22.9	23.4
TOTAL EXPENSES	441.8	416.9
Operating Income (Loss)	118.7	115.8
Other Income (Expense):
Interest Income	4.5	3.2
Allowance for Equity Funds Used During Construction	2.1	2.3
Interest Expense	(27.7)	(22.5)
INCOME BEFORE INCOME TAX EXPENSE	97.6	98.8
Income Tax Expense (Credit)	29.2	24.1
Net Income (Loss)	68.4	74.7
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	738.4	756.7
Sales to AEP Affiliates	5.7	4.8
Other Revenues	2	2.1
TOTAL REVENUES	746.1	763.6
Expenses
Purchased Electricity for Resale	188.3	164.9
Purchased Electricity from AEP Affiliates	32	49.1
Amortization Of Generation Deferrals	60.9	55.1
Other Operation	121.2	167.9
Maintenance	37.2	33.7
Depreciation and Amortization	57.3	61.3
Taxes Other Than Income Taxes	98.5	97.6
TOTAL EXPENSES	595.4	629.6
Operating Income (Loss)	150.7	134
Other Income (Expense):
Interest Income	2.5	1.5
Carrying Costs Income	1.9	1.9
Allowance for Equity Funds Used During Construction	2.4	1.7
Interest Expense	(25)	(31.4)
INCOME BEFORE INCOME TAX EXPENSE	132.5	107.7
Income Tax Expense (Credit)	46.3	37.5
Net Income (Loss)	86.2	70.2
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	301.9	271.8
Sales to AEP Affiliates	1.1	1
Other Revenues	1.1	1.5
TOTAL REVENUES	304.1	274.3
Expenses
Fuel and Other Consumables Used for Electric Generation	12.3	15.5
Purchased Electricity for Resale	125.3	93.3
Other Operation	67.4	62.9
Maintenance	34.2	21.8
Depreciation and Amortization	33.5	35.3
Taxes Other Than Income Taxes	10.6	9.7
TOTAL EXPENSES	283.3	238.5
Operating Income (Loss)	20.8	35.8
Other Income (Expense):
Interest Income	0.1	0.2
Allowance for Equity Funds Used During Construction	0.4	2.3
Interest Expense	(13.6)	(14.4)
INCOME BEFORE INCOME TAX EXPENSE	7.7	23.9
Income Tax Expense (Credit)	2.9	8.2
Net Income (Loss)	4.8	15.7
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	396.3	375.4
Sales to AEP Affiliates	4.6	3.1
Other Revenues	0.4	0.5
TOTAL REVENUES	401.3	379
Expenses
Fuel and Other Consumables Used for Electric Generation	130.9	121.9
Purchased Electricity for Resale	32.4	28.1
Other Operation	78	77.1
Maintenance	32.2	31.1
Depreciation and Amortization	50.8	47.5
Taxes Other Than Income Taxes	23.3	21.9
TOTAL EXPENSES	347.6	327.6
Operating Income (Loss)	53.7	51.4
Other Income (Expense):
Interest Income	0.9	0
Allowance for Equity Funds Used During Construction	0.8	7.4
Interest Expense	(29.9)	(27.9)
INCOME BEFORE INCOME TAX EXPENSE	25.5	30.9
Income Tax Expense (Credit)	9.5	7.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries	1.3	1
Net Income (Loss)	17.3	24.5
Net Income Attributable to Noncontrolling Interests	1	1.1
Earnings Attributable to Common Shareholders	$ 16.3	$ 23.4

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net Income (Loss)	$ 594.2	$ 503.1
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(16.1)	(7.4)
Securities Available for Sale, Net of Tax	1.2	0.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.2	0.1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(14.7)	(6.7)
TOTAL COMPREHENSIVE INCOME (LOSS)	579.5	496.4
Total Comprehensive Income Attributable to Noncontrolling Interest	2	1.9
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	577.5	494.5
Appalachian Power Co [Member]
Net Income (Loss)	110.6	126.3
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.3)	(0.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.5)	(0.5)
TOTAL COMPREHENSIVE INCOME (LOSS)	110.1	125.8
Indiana Michigan Power Co [Member]
Net Income (Loss)	68.4	74.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.3	0.4
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.4
TOTAL COMPREHENSIVE INCOME (LOSS)	68.7	75.1
Ohio Power Co [Member]
Net Income (Loss)	86.2	70.2
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.4)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.2)	(0.4)
TOTAL COMPREHENSIVE INCOME (LOSS)	86	69.8
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	4.8	15.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.2)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.2)	(0.2)
TOTAL COMPREHENSIVE INCOME (LOSS)	4.6	15.5
Southwestern Electric Power Co [Member]
Net Income (Loss)	17.3	24.5
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.5	0.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.2)	(0.2)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.3
TOTAL COMPREHENSIVE INCOME (LOSS)	17.6	24.8
Total Comprehensive Income Attributable to Noncontrolling Interest	1	1.1
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 16.6	$ 23.7

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flow Hedges, Tax	$ (8.7)	$ (4)
Securities Available for Sale, Tax	0.6	0.3
Amortization of Pension and OPEB Deferred Costs, Tax	0.1	0.1
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.2)	(0.2)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.2	0.2
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.2)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.2	0.2
Amortization of Pension and OPEB Deferred Costs, Tax	$ (0.1)	$ (0.1)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	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]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]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]Appalachian Power Co [Member]	Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member]	Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member]	Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member]	Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Southwestern Electric Power Co [Member]
Beginning Balance at Dec. 31, 2015	$ 17,904.9	$ 3,475	$ 2,036.4	$ 1,986.6	$ 1,119.9	$ 2,169.7	$ 3,324	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,296.5	$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 8,398.3	$ 1,388.7	$ 1,015.6	$ 822.3	$ 594.5	$ 1,366.3	$ (127.1)	$ (2.8)	$ (16.7)	$ 4.3	$ 4.2	$ (9.4)	$ 13.2	$ 0.5
Beginning Balance, Shares at Dec. 31, 2015							511,400,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	12.1						$ 1.3						10.8
Issuance of Common Stock, Shares							200,000
Common Stock Dividends	(276.5)																		(275.3)
Common Stock Dividends		(75)	(31.3)	(75)		(30)														(75)	(31.3)	(75)		(30)
Common Stock Dividends						(1.2)																									(1.2)	(1.2)
Other Changes in Equity	4.8												2.9						0.6												1.3
Net Income (Loss)																			501.2					23.4
Net Income Attributable to Noncontrolling Interests	1.9					1.1																									1.9	1.1
Net Income (Loss)	503.1	126.3	74.7	70.2	15.7	24.5														126.3	74.7	70.2	15.7
Other Comprehensive Income (Loss)	(6.7)	(0.5)	0.4	(0.4)	(0.2)	0.3																			(6.7)	(0.5)	0.4	(0.4)	(0.2)	0.3
Ending Balance at Mar. 31, 2016	18,141.7	3,525.8	2,080.2	1,981.4	1,135.4	2,163.3	$ 3,325.3	260.4	56.6	321.2	157.2	135.7	6,310.2	1,828.7	980.9	838.8	364	676.6	8,624.8	1,440	1,059	817.5	610.2	1,359.7	(133.8)	(3.3)	(16.3)	3.9	4	(9.1)	15.2	0.4
Ending Balance, Shares at Mar. 31, 2016							511,600,000
Beginning Balance at Dec. 31, 2016	$ 17,420.1	3,583.5	2,151.8	2,117.5	$ 1,214.1	2,215.2	$ 3,328.3	260.4	56.6	321.2	157.2	135.7	6,332.6	1,828.7	980.9	838.8	364	676.6	7,892.4	1,502.8	1,130.5	954.5	689.5	1,411.9	(156.3)	(8.4)	(16.2)	3	3.4	(9.4)	23.1	0.4
Beginning Balance, Shares at Dec. 31, 2016	512,048,520				10,482,000		512,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock Dividends	$ (291.4)																		(290.3)
Common Stock Dividends		(30)	(31.3)	(65)	$ (17.5)	(27.5)														(30)	(31.3)	(65)	(17.5)	(27.5)
Common Stock Dividends						(1.1)																									(1.1)	(1.1)
Other Changes in Equity	3.5												2.9						0												0.6
Net Income (Loss)																			592.2					16.3
Net Income Attributable to Noncontrolling Interests	2					1																									2	1
Net Income (Loss)	594.2	110.6	68.4	86.2	4.8	17.3														110.6	68.4	86.2	4.8
Other Comprehensive Income (Loss)	(14.7)	(0.5)	0.3	(0.2)	(0.2)	0.3																			(14.7)	(0.5)	0.3	(0.2)	(0.2)	0.3
Ending Balance at Mar. 31, 2017	$ 17,711.7	$ 3,663.6	$ 2,189.2	$ 2,138.5	$ 1,201.2	$ 2,204.2	$ 3,328.3	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,335.5	$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 8,194.3	$ 1,583.4	$ 1,167.6	$ 975.7	$ 676.8	$ 1,400.7	$ (171)	$ (8.9)	$ (15.9)	$ 2.8	$ 3.2	$ (9.1)	$ 24.6	$ 0.3
Ending Balance, Shares at Mar. 31, 2017	512,048,663				10,482,000		512,000,000

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents		$ 175	$ 210.5
Other Temporary Investments		275	331.7
Accounts Receivable:
Customers		601	705.1
Accrued Unbilled Revenues		143.6	158.7
Pledged Accounts Receivable - AEP Credit		900.1	972.7
Miscellaneous		104.2	118.1
Allowance for Uncollectible Accounts		(37.7)	(37.9)
Total Accounts Receivable		1,711.2	1,916.7
Fuel		408	423.8
Materials and Supplies		547.3	543.5
Risk Management Assets		85	94.5
Regulatory Asset for Under-Recovered Fuel Costs		158.5	156.6
Margin Deposits		105.7	79.9
Assets Held for Sale		9.7	1,951.2
Prepayments and Other Current Assets		141	325.5
TOTAL CURRENT ASSETS		3,616.4	6,033.9
Property, Plant and Equipment
Generation		20,290.3	19,848.9
Transmission		16,874.8	16,658.7
Distribution		19,136.6	18,900.8
Other Property, Plant and Equipment		3,412	3,444.3
Construction Work in Progress		3,196.8	3,183.9
Total Property, Plant and Equipment		62,910.5	62,036.6
Accumulated Depreciation and Amortization		16,674.2	16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		46,236.3	45,639.3
Other Noncurrent Assets
Regulatory Assets		5,583.1	5,625.5
Securitized Assets		1,425.2	1,486.1
Spent Nuclear Fuel and Decommissioning Trusts		2,333.2	2,256.2
Goodwill		52.5	52.5
Long-term Risk Management Assets		310.5	289.1
Deferred Charges and Other Noncurrent Assets		2,171.1	2,085.1
TOTAL OTHER NONCURRENT ASSETS		11,875.6	11,794.5
TOTAL ASSETS		61,728.3	63,467.7
Current Liabilities
Accounts Payable		1,116.9	1,688.5
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	572	673
Other Short-term Debt		964	1,040
Total Short-term Debt		1,536	1,713
Long-term Debt Due Within One Year		2,514.2	2,878
Risk Management Liabilities		68.2	53.4
Customer Deposits		342	343.2
Accrued Taxes		1,078.5	1,048
Accrued Interest		239.7	227.2
Regulatory Liability for Over-Recovered Fuel Costs		7.5	8
Liabilities Held for Sale		3.5	235.9
Other Current Liabilities		1,008	1,302.8
TOTAL CURRENT LIABILITIES		7,914.5	9,498
Noncurrent Liabilities
Long-term Debt		16,722.2	17,378.4
Long-term Debt - Affiliated		0	0
Long-term Risk Management Liabilities		344.8	316.2
Deferred Income Taxes		11,981.6	11,884.4
Regulatory Liabilities and Deferred Investment Tax Credits		3,867.6	3,751.3
Asset Retirement Obligations		1,869.8	1,830.6
Employee Benefits and Pension Obligations		586.2	614.1
Deferred Credits and Other Noncurrent Liabilities		728.3	774.6
TOTAL NONCURRENT LIABILITIES		36,100.5	36,549.6
TOTAL LIABILITIES		44,015	46,047.6
Rate Matters
Commitments and Contingencies
Contingently Redeemable Performance Share Awards		1.6	0
Equity
Common Stock		3,328.3	3,328.3
Paid-in Capital		6,335.5	6,332.6
Retained Earnings		8,194.3	7,892.4
Accumulated Other Comprehensive Income (Loss)		(171)	(156.3)
TOTAL COMMON SHAREHOLDER'S EQUITY		17,687.1	17,397
Noncontrolling Interests		24.6	23.1
TOTAL EQUITY		17,711.7	17,420.1
TOTAL LIABILITIES AND EQUITY		61,728.3	63,467.7
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		3	2.7
Restricted Cash for Securitized Funding		8	15.8
Advances to Affiliates		23.7	24.1
Accounts Receivable:
Customers		125	131.4
Affiliated Companies		59.9	54.4
Accrued Unbilled Revenues		52.6	52.7
Miscellaneous		3.9	0.9
Allowance for Uncollectible Accounts		(3.3)	(3.5)
Total Accounts Receivable		238.1	235.9
Fuel		118.7	112
Materials and Supplies		99	98.8
Risk Management Assets		1.1	2.6
Accrued Tax Benefits		1.7	4.2
Regulatory Asset for Under-Recovered Fuel Costs		67.3	68.4
Margin Deposits		9.6	17.5
Prepayments and Other Current Assets		10.2	9.7
TOTAL CURRENT ASSETS		580.4	591.7
Property, Plant and Equipment
Generation		6,386.4	6,332.8
Transmission		2,809.5	2,796.9
Distribution		3,616.3	3,569.1
Other Property, Plant and Equipment		378.3	373.5
Construction Work in Progress		386.1	390.3
Total Property, Plant and Equipment		13,576.6	13,462.6
Accumulated Depreciation and Amortization		3,705.4	3,636.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,871.2	9,825.8
Other Noncurrent Assets
Regulatory Assets		1,111.4	1,121.1
Securitized Assets		299.6	305.3
Long-term Risk Management Assets		0.2	0
Deferred Charges and Other Noncurrent Assets		143.1	133.3
TOTAL OTHER NONCURRENT ASSETS		1,554.3	1,559.7
TOTAL ASSETS		12,005.9	11,977.2
Current Liabilities
Advances from Affiliates		182.4	79.6
Accounts Payable		170.9	253.7
Affiliated Companies		77.7	82.6
Short-term Debt:
Long-term Debt Due Within One Year		399	503.1
Risk Management Liabilities		6.6	0.3
Customer Deposits		84.3	83.1
Accrued Taxes		118.9	107.6
Accrued Interest		63.1	40.6
Other Current Liabilities		88.9	129.5
TOTAL CURRENT LIABILITIES		1,191.8	1,280.1
Noncurrent Liabilities
Long-term Debt		3,519.8	3,530.8
Long-term Risk Management Liabilities		0.1	0.9
Deferred Income Taxes		2,722.9	2,672.3
Regulatory Liabilities and Deferred Investment Tax Credits		629.4	627.8
Asset Retirement Obligations		107.9	108.8
Employee Benefits and Pension Obligations		103.7	108.5
Deferred Credits and Other Noncurrent Liabilities		66.7	64.5
TOTAL NONCURRENT LIABILITIES		7,150.5	7,113.6
TOTAL LIABILITIES		8,342.3	8,393.7
Rate Matters
Commitments and Contingencies
Equity
Common Stock		260.4	260.4
Paid-in Capital		1,828.7	1,828.7
Retained Earnings		1,583.4	1,502.8
Accumulated Other Comprehensive Income (Loss)		(8.9)	(8.4)
TOTAL EQUITY		3,663.6	3,583.5
TOTAL LIABILITIES AND EQUITY		12,005.9	11,977.2
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.2	1.2
Advances to Affiliates		12.5	12.5
Accounts Receivable:
Customers		47.6	60.2
Affiliated Companies		57.4	51
Accrued Unbilled Revenues		4.6	1.5
Miscellaneous		0.8	0.7
Total Accounts Receivable		110.4	113.4
Fuel		38.1	32.3
Materials and Supplies		154.1	150.8
Risk Management Assets		2.4	3.5
Accrued Tax Benefits		56.5	37.7
Regulatory Asset for Under-Recovered Fuel Costs		10.3	26.1
Accrued Reimbursement of Spent Nuclear Fuel Costs		9.1	22.1
Prepayments and Other Current Assets		23.7	19.9
TOTAL CURRENT ASSETS		418.3	419.5
Property, Plant and Equipment
Generation		4,219.6	4,056.1
Transmission		1,472.2	1,472.8
Distribution		1,929.7	1,899.3
Other Property, Plant and Equipment		520.6	550.2
Construction Work in Progress		521	654.2
Total Property, Plant and Equipment		8,663.1	8,632.6
Accumulated Depreciation and Amortization		2,984.1	3,005.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,679	5,627.5
Other Noncurrent Assets
Regulatory Assets		906.1	916.6
Spent Nuclear Fuel and Decommissioning Trusts		2,333.2	2,256.2
Long-term Risk Management Assets		0.6	0
Deferred Charges and Other Noncurrent Assets		117.1	121.5
TOTAL OTHER NONCURRENT ASSETS		3,357	3,294.3
TOTAL ASSETS		9,454.3	9,341.3
Current Liabilities
Advances from Affiliates		286.8	215.2
Accounts Payable		133.4	179
Affiliated Companies		69.2	75.6
Short-term Debt:
Long-term Debt Due Within One Year		199.1	209.3
Risk Management Liabilities		2.8	0.3
Customer Deposits		34.4	34.3
Accrued Taxes		89.1	77.2
Accrued Interest		11.9	31.7
Obligations Under Capital Leases		9.5	9.4
Other Current Liabilities		101	123.4
TOTAL CURRENT LIABILITIES		937.2	955.4
Noncurrent Liabilities
Long-term Debt		2,240.4	2,262.1
Long-term Risk Management Liabilities		0.1	0.8
Deferred Income Taxes		1,579.2	1,527.4
Regulatory Liabilities and Deferred Investment Tax Credits		1,120	1,065.5
Asset Retirement Obligations		1,271.6	1,257.9
Deferred Credits and Other Noncurrent Liabilities		116.6	120.4
TOTAL NONCURRENT LIABILITIES		6,327.9	6,234.1
TOTAL LIABILITIES		7,265.1	7,189.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,167.6	1,130.5
Accumulated Other Comprehensive Income (Loss)		(15.9)	(16.2)
TOTAL EQUITY		2,189.2	2,151.8
TOTAL LIABILITIES AND EQUITY		9,454.3	9,341.3
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3	3.1
Restricted Cash for Securitized Funding		16	27.2
Advances to Affiliates		0	24.2
Accounts Receivable:
Customers		41.5	51.1
Affiliated Companies		52.4	66.3
Accrued Unbilled Revenues		14.4	21
Miscellaneous		0.8	0.9
Allowance for Uncollectible Accounts		(0.4)	(0.4)
Total Accounts Receivable		108.7	138.9
Materials and Supplies		43.5	45.9
Emission Allowances		22.3	20.4
Risk Management Assets		0.1	0.2
Prepayments and Other Current Assets		12.5	11
TOTAL CURRENT ASSETS		206.1	270.9
Property, Plant and Equipment
Transmission		2,326.7	2,319.2
Distribution		4,493.2	4,457.2
Other Property, Plant and Equipment		457.1	443.7
Construction Work in Progress		243.4	221.5
Total Property, Plant and Equipment		7,520.4	7,441.6
Accumulated Depreciation and Amortization		2,140	2,116
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,380.4	5,325.6
Other Noncurrent Assets
Notes Receivable - Affiliated		32.3	32.3
Regulatory Assets		1,079.8	1,107.5
Securitized Assets		55.9	62.1
Deferred Charges and Other Noncurrent Assets		240.5	295.5
TOTAL OTHER NONCURRENT ASSETS		1,408.5	1,497.4
TOTAL ASSETS		6,995	7,093.9
Current Liabilities
Advances from Affiliates		18.3	0
Accounts Payable		129.3	175.4
Affiliated Companies		91.4	95.6
Short-term Debt:
Long-term Debt Due Within One Year		46.8	46.4
Risk Management Liabilities		6.3	5.9
Customer Deposits		71.9	71
Accrued Taxes		413.5	520.3
Accrued Interest		38.4	31.2
Other Current Liabilities		255.5	236
TOTAL CURRENT LIABILITIES		1,071.4	1,181.8
Noncurrent Liabilities
Long-term Debt		1,695.2	1,717.5
Long-term Risk Management Liabilities		118.3	113.1
Deferred Income Taxes		1,382.3	1,346.1
Regulatory Liabilities and Deferred Investment Tax Credits		533.4	506.2
Employee Benefits and Pension Obligations		28.8	27.8
Deferred Credits and Other Noncurrent Liabilities		27.1	83.9
TOTAL NONCURRENT LIABILITIES		3,785.1	3,794.6
TOTAL LIABILITIES		4,856.5	4,976.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		975.7	954.5
Accumulated Other Comprehensive Income (Loss)		2.8	3
TOTAL EQUITY		2,138.5	2,117.5
TOTAL LIABILITIES AND EQUITY		6,995	7,093.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1.3	1.5
Accounts Receivable:
Customers		24.8	27.5
Affiliated Companies		16.1	26.8
Miscellaneous		1.3	4.4
Allowance for Uncollectible Accounts		(0.3)	(0.2)
Total Accounts Receivable		41.9	58.5
Fuel		19.1	22.9
Materials and Supplies		45	44.6
Risk Management Assets		0.5	0.8
Accrued Tax Benefits		49.3	27.3
Regulatory Asset for Under-Recovered Fuel Costs		46.9	33.8
Prepayments and Other Current Assets		5.8	6
TOTAL CURRENT ASSETS		209.8	195.4
Property, Plant and Equipment
Generation		1,566.8	1,559.3
Transmission		842.8	832.8
Distribution		2,364.3	2,322.4
Other Property, Plant and Equipment		268.3	233.2
Construction Work in Progress		106.3	148.2
Total Property, Plant and Equipment		5,148.5	5,095.9
Accumulated Depreciation and Amortization		1,338.3	1,272.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,810.2	3,823.2
Other Noncurrent Assets
Regulatory Assets		381.1	340.2
Employee Benefits and Pension Assets		10.5	10.4
Deferred Charges and Other Noncurrent Assets		39.5	10
TOTAL OTHER NONCURRENT ASSETS		431.1	360.6
TOTAL ASSETS		4,451.1	4,379.2
Current Liabilities
Advances from Affiliates		163.7	52
Accounts Payable		92.5	116.3
Affiliated Companies		42	56.2
Short-term Debt:
Long-term Debt Due Within One Year		0.5	0.5
Customer Deposits		50.9	49.7
Accrued Taxes		42.7	21
Accrued Interest		14	13.9
Provision for Refund		34.7	46.1
Other Current Liabilities		34.3	47.8
TOTAL CURRENT LIABILITIES		475.3	403.5
Noncurrent Liabilities
Long-term Debt		1,285.6	1,285.5
Deferred Income Taxes		1,086.3	1,058.8
Regulatory Liabilities and Deferred Investment Tax Credits		326.5	339.7
Asset Retirement Obligations		53.5	52.8
Employee Benefits and Pension Obligations		12.1	13.6
Deferred Credits and Other Noncurrent Liabilities		10.6	11.2
TOTAL NONCURRENT LIABILITIES		2,774.6	2,761.6
TOTAL LIABILITIES		3,249.9	3,165.1
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		676.8	689.5
Accumulated Other Comprehensive Income (Loss)		3.2	3.4
TOTAL EQUITY		1,201.2	1,214.1
TOTAL LIABILITIES AND EQUITY		4,451.1	4,379.2
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		10.3	10.3
Advances to Affiliates		2	169.8
Accounts Receivable:
Customers		36.4	48.5
Affiliated Companies		15.7	29.3
Miscellaneous		19.9	17.5
Allowance for Uncollectible Accounts		(1)	(1.2)
Total Accounts Receivable		71	94.1
Fuel		94.2	107.1
Materials and Supplies		68.8	68.4
Risk Management Assets		0.6	0.9
Accrued Tax Benefits		83.5	51.5
Regulatory Asset for Under-Recovered Fuel Costs		11.6	8.4
Prepayments and Other Current Assets		38.9	35.5
TOTAL CURRENT ASSETS		380.9	546
Property, Plant and Equipment
Generation		4,611.8	4,607.6
Transmission		1,600.2	1,584.2
Distribution		2,039.5	2,020.6
Other Property, Plant and Equipment		677	670.4
Construction Work in Progress		125.2	113.8
Total Property, Plant and Equipment		9,053.7	8,996.6
Accumulated Depreciation and Amortization		2,608	2,567.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,445.7	6,429.5
Other Noncurrent Assets
Regulatory Assets		559.1	551.2
Deferred Charges and Other Noncurrent Assets		147.5	99.9
TOTAL OTHER NONCURRENT ASSETS		706.6	651.1
TOTAL ASSETS		7,533.2	7,626.6
Current Liabilities
Advances from Affiliates		167.9	0
Accounts Payable		99.8	117.5
Affiliated Companies		43.2	68.5
Short-term Debt:
Long-term Debt Due Within One Year		485.4	353.7
Risk Management Liabilities		0.4	0.3
Customer Deposits		62.7	62.1
Accrued Taxes		84.7	40.9
Accrued Interest		24.8	45.1
Obligations Under Capital Leases		11.3	11.8
Other Current Liabilities		62.9	83.9
TOTAL CURRENT LIABILITIES		1,043.1	783.8
Noncurrent Liabilities
Long-term Debt		1,942.3	2,325.4
Deferred Income Taxes		1,652.3	1,606.9
Regulatory Liabilities and Deferred Investment Tax Credits		439.1	438.9
Asset Retirement Obligations		148.3	147.1
Employee Benefits and Pension Obligations		29.8	34.1
Obligations Under Capital Leases		64.6	65.5
Deferred Credits and Other Noncurrent Liabilities		9.5	9.7
TOTAL NONCURRENT LIABILITIES		4,285.9	4,627.6
TOTAL LIABILITIES		5,329	5,411.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,400.7	1,411.9
Accumulated Other Comprehensive Income (Loss)		(9.1)	(9.4)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,203.9	2,214.8
Noncontrolling Interests		0.3	0.4
TOTAL EQUITY		2,204.2	2,215.2
TOTAL LIABILITIES AND EQUITY		$ 7,533.2	$ 7,626.6
[1]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Condensed Consolidated Balance7

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	$ 175	$ 210.5
Other Temporary Investments	275	331.7
Fuel	408	423.8
Property, Plant and Equipment
Other Property, Plant and Equipment	3,412	3,444.3
Accumulated Depreciation and Amortization	16,674.2	16,397.3
Current Liabilities
Long-term Debt Due Within One Year	2,514.2	2,878
Noncurrent Liabilities
Long-term Debt	$ 16,722.2	$ 17,378.4
Equity
Common Stock, Par Value Per Share	$ 6.50	$ 6.50
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	512,048,663	512,048,520
Treasury Stock, Shares	20,336,592	20,336,592
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 3	$ 2.7
Fuel	118.7	112
Property, Plant and Equipment
Other Property, Plant and Equipment	378.3	373.5
Accumulated Depreciation and Amortization	3,705.4	3,636.8
Current Liabilities
Long-term Debt Due Within One Year	399	503.1
Noncurrent Liabilities
Long-term Debt	$ 3,519.8	$ 3,530.8
Equity
Common Stock, Shares Authorized	30,000,000	30,000,000
Common Stock, Shares Outstanding	13,499,500	13,499,500
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 1.2	$ 1.2
Fuel	38.1	32.3
Property, Plant and Equipment
Other Property, Plant and Equipment	520.6	550.2
Accumulated Depreciation and Amortization	2,984.1	3,005.1
Current Liabilities
Long-term Debt Due Within One Year	199.1	209.3
Noncurrent Liabilities
Long-term Debt	$ 2,240.4	$ 2,262.1
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	2,500,000	2,500,000
Common Stock, Shares Outstanding	1,400,000	1,400,000
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 120,700	$ 130,900
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3	3.1
Property, Plant and Equipment
Other Property, Plant and Equipment	457.1	443.7
Accumulated Depreciation and Amortization	2,140	2,116
Current Liabilities
Long-term Debt Due Within One Year	46.8	46.4
Noncurrent Liabilities
Long-term Debt	$ 1,695.2	$ 1,717.5
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 46.7	$ 46.3
Noncurrent Liabilities
Long-term Debt	71.3	93.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	1.3	1.5
Fuel	19.1	22.9
Property, Plant and Equipment
Other Property, Plant and Equipment	268.3	233.2
Accumulated Depreciation and Amortization	1,338.3	1,272.7
Current Liabilities
Long-term Debt Due Within One Year	0.5	0.5
Noncurrent Liabilities
Long-term Debt	$ 1,285.6	$ 1,285.5
Equity
Common Stock, Par Value Per Share	$ 15	$ 15
Common Stock, Shares Authorized	11,000,000	11,000,000
Common Stock, Shares, Issued	10,482,000	10,482,000
Common Stock, Shares Outstanding	9,013,000	9,013,000
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 10.3	$ 10.3
Fuel	94.2	107.1
Property, Plant and Equipment
Other Property, Plant and Equipment	677	670.4
Accumulated Depreciation and Amortization	2,608	2,567.1
Current Liabilities
Long-term Debt Due Within One Year	485.4	353.7
Noncurrent Liabilities
Long-term Debt	$ 1,942.3	$ 2,325.4
Equity
Common Stock, Par Value Per Share	$ 18	$ 18
Common Stock, Shares Authorized	7,600,000	7,600,000
Common Stock, Shares Outstanding	7,536,640	7,536,640
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Current Assets
Cash and Cash Equivalents	$ 8.9	$ 8.7
Fuel	29.1	34.3
Property, Plant and Equipment
Other Property, Plant and Equipment	268.5	267.5
Accumulated Depreciation and Amortization	158.6	155.6
AEP Subsidiaries [Member]
Current Assets
Other Temporary Investments	260	322.5
Current Liabilities
Long-term Debt Due Within One Year	554.2	427.5
Noncurrent Liabilities
Long-term Debt	$ 1,461.1	$ 1,737.5

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating Activities
Net Income (Loss)	$ 594.2	$ 503.1
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	481.9	497.1
Deferred Income Taxes	136.2	330.2
Other Asset Impairment Charges	11.2	0
Carrying Costs Income	(5.9)	(3.9)
Allowance for Equity Funds Used During Construction	(21.2)	(31.7)
Mark-to-Market of Risk Management Contracts	6	20.9
Amortization of Nuclear Fuel	35.1	40.5
Property Taxes	(44.4)	(34.4)
Deferred Fuel Over/Under-Recovery, Net	19.3	10.6
Gain on Sale of Merchant Generation Assets	(226.5)	0
Recovery of Ohio Capacity Costs	30.2	35.1
Change in Other Noncurrent Assets	(104.4)	(68.3)
Change in Other Noncurrent Liabilities	45	1.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	235.8	(10.8)
Fuel, Materials and Supplies	13.4	(95.4)
Accounts Payable	(250.7)	(34.4)
Accrued Taxes, Net	186.8	(169.2)
Other Current Assets	(45.9)	21.6
Other Current Liabilities	(289.3)	(212.9)
Net Cash Flows from (Used for) Operating Activities	806.8	799.9
Investing Activities
Construction Expenditures	(1,365.8)	(1,203.5)
Change in Other Temporary Investments, Net	55.6	122.8
Purchases of Investment Securities	(506)	(1,152)
Sales of Investment Securities	487.9	1,137.7
Acquisitions of Nuclear Fuel	(3.7)	(45.5)
Proceeds from Sale of Merchant Generation Assets	2,159.6	0
Other Investing Activities	17.2	2.2
Net Cash Flows from (Used for) Investing Activities	844.8	(1,138.3)
Financing Activities
Issuance of Common Stock, Net	0	12.1
Issuance of Long-term Debt	82.9	525.1
Change in Short-term Debt, Net	(177)	421
Retirement of Long-term Debt	(1,242.3)	(322.4)
Make Whole Premium on Extinguishment of Long-term Debt	(44.9)	0
Principal Payments for Capital Lease Obligations	(16.6)	(24.9)
Dividends Paid on Common Stock	(291.4)	(276.5)
Other Financing Activities	2.2	18
Net Cash Flows from (Used for) Financing Activities	(1,687.1)	352.4
Net Increase (Decrease) in Cash and Cash Equivalents	(35.5)	14
Cash and Cash Equivalents at Beginning of Period	210.5	176.4
Cash and Cash Equivalents at End of Period	175	190.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	205.9	199
Net Cash Paid (Received) for Income Taxes	(88.8)	7.3
Noncash Acquisitions Under Capital Leases	11.4	45.4
Construction Expenditures Included in Current Liabilities as of March 31,	515.6	544.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	0	29.1
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	1	0
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	110.6	126.3
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	100.6	95.5
Deferred Income Taxes	52.2	30.9
Allowance for Equity Funds Used During Construction	(1.5)	(2.3)
Mark-to-Market of Risk Management Contracts	6.8	9.1
Deferred Fuel Over/Under-Recovery, Net	1.1	5.1
Change in Other Noncurrent Assets	1	17.7
Change in Other Noncurrent Liabilities	(3.7)	(9)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(2.2)	(26.1)
Fuel, Materials and Supplies	(6.9)	(28.3)
Accounts Payable	(12.7)	(2.9)
Accrued Taxes, Net	9.4	54.5
Other Current Assets	7.8	(4.1)
Other Current Liabilities	(3.5)	(8.4)
Net Cash Flows from (Used for) Operating Activities	259	258
Investing Activities
Construction Expenditures	(223.7)	(168.9)
Change in Restricted Cash for Securitized Funding	7.8	7.3
Change in Advances to Affiliates, Net	0.4	0.8
Other Investing Activities	1.4	4.1
Net Cash Flows from (Used for) Investing Activities	(214.1)	(156.7)
Financing Activities
Issuance of Long-term Debt	0	124.8
Change in Advances from Affiliates, Net	102.8	(9.8)
Retirement of Long-term Debt	(115.9)	(136.5)
Principal Payments for Capital Lease Obligations	(1.8)	(1.5)
Dividends Paid on Common Stock	(30)	(75)
Other Financing Activities	0.3	0.3
Net Cash Flows from (Used for) Financing Activities	(44.6)	(97.7)
Net Increase (Decrease) in Cash and Cash Equivalents	0.3	3.6
Cash and Cash Equivalents at Beginning of Period	2.7	2.8
Cash and Cash Equivalents at End of Period	3	6.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	23.8	23.1
Net Cash Paid (Received) for Income Taxes	0	(17.9)
Noncash Acquisitions Under Capital Leases	0.5	0.7
Construction Expenditures Included in Current Liabilities as of March 31,	63.7	70.4
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	68.4	74.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	50	47.1
Deferred Income Taxes	48.8	44
Deferral of Incremental Nuclear Refueling Outage Expenses, Net	16.6	(8.4)
Allowance for Equity Funds Used During Construction	(2.1)	(2.3)
Mark-to-Market of Risk Management Contracts	2.3	2.4
Amortization of Nuclear Fuel	35.1	40.5
Deferred Fuel Over/Under-Recovery, Net	19.6	3.8
Change in Other Noncurrent Assets	(17.6)	(4.8)
Change in Other Noncurrent Liabilities	13.5	9.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	3	(2)
Fuel, Materials and Supplies	(8.5)	(16)
Accounts Payable	(22.5)	(9.9)
Accrued Taxes, Net	(6.9)	2.5
Other Current Assets	15.8	6.1
Other Current Liabilities	(41.2)	(32.5)
Net Cash Flows from (Used for) Operating Activities	174.3	154.3
Investing Activities
Construction Expenditures	(159.7)	(136.4)
Change in Advances to Affiliates, Net	0	(0.6)
Purchases of Investment Securities	(505.5)	(1,151.6)
Sales of Investment Securities	487.9	1,137.7
Acquisitions of Nuclear Fuel	(3.7)	(45.5)
Other Investing Activities	2	3.3
Net Cash Flows from (Used for) Investing Activities	(179)	(193.1)
Financing Activities
Issuance of Long-term Debt	76.7	394.8
Change in Advances from Affiliates, Net	71.6	(284.8)
Retirement of Long-term Debt	(109.5)	(28.8)
Principal Payments for Capital Lease Obligations	(2.9)	(9.6)
Dividends Paid on Common Stock	(31.3)	(31.3)
Other Financing Activities	0.1	0.7
Net Cash Flows from (Used for) Financing Activities	4.7	41
Net Increase (Decrease) in Cash and Cash Equivalents	0	2.2
Cash and Cash Equivalents at Beginning of Period	1.2	1.1
Cash and Cash Equivalents at End of Period	1.2	3.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	44.3	35.2
Net Cash Paid (Received) for Income Taxes	0.6	(4.9)
Noncash Acquisitions Under Capital Leases	1.5	14.9
Construction Expenditures Included in Current Liabilities as of March 31,	75.9	68.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	0	29.1
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	1	0
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	86.2	70.2
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	57.3	61.3
Amortization Of Generation Deferrals	60.9	55.1
Deferred Income Taxes	36.7	7.3
Carrying Costs Income	(1.9)	(1.9)
Allowance for Equity Funds Used During Construction	(2.4)	(1.7)
Mark-to-Market of Risk Management Contracts	5.7	26.9
Property Taxes	58.4	56
Change in Other Noncurrent Assets	(45.8)	(16.2)
Change in Other Noncurrent Liabilities	30.6	6.5
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	30.2	(4.7)
Fuel, Materials and Supplies	(1.8)	(3)
Accounts Payable	(34.9)	(30.4)
Customer Deposits	0.9	24
Accrued Taxes, Net	(107.2)	(148.4)
Other Current Assets	(0.3)	(0.4)
Other Current Liabilities	(32.1)	(20.7)
Net Cash Flows from (Used for) Operating Activities	140.5	79.9
Investing Activities
Construction Expenditures	(108.4)	(99.2)
Change in Restricted Cash for Securitized Funding	11.2	11.5
Change in Advances to Affiliates, Net	24.2	109.2
Other Investing Activities	2	3.1
Net Cash Flows from (Used for) Investing Activities	(71)	24.6
Financing Activities
Change in Advances from Affiliates, Net	18.3	0
Retirement of Long-term Debt	(22.5)	(22.8)
Principal Payments for Capital Lease Obligations	(1)	(1)
Dividends Paid on Common Stock	(65)	(75)
Other Financing Activities	0.6	0.5
Net Cash Flows from (Used for) Financing Activities	(69.6)	(98.3)
Net Increase (Decrease) in Cash and Cash Equivalents	(0.1)	6.2
Cash and Cash Equivalents at Beginning of Period	3.1	3.1
Cash and Cash Equivalents at End of Period	3	9.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	17.2	17.8
Net Cash Paid (Received) for Income Taxes	1.7	72.5
Noncash Acquisitions Under Capital Leases	1.3	0.8
Construction Expenditures Included in Current Liabilities as of March 31,	28.3	23.1
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	4.8	15.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	33.5	35.3
Deferred Income Taxes	27.4	30.5
Allowance for Equity Funds Used During Construction	(0.4)	(2.3)
Mark-to-Market of Risk Management Contracts	0.3	0
Property Taxes	(29.8)	(24.1)
Deferred Fuel Over/Under-Recovery, Net	(13.1)	(8.3)
Customer Refund Liability, Current	(11.4)	6.7
Change in Regulatory Assets	(6.7)	(3.9)
Change in Regulatory Liabilities	(0.4)	(1.1)
Change in Other Noncurrent Assets	(2.6)	(6.3)
Change in Other Noncurrent Liabilities	(1.5)	(0.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	16.6	5
Fuel, Materials and Supplies	3.4	(3.5)
Accounts Payable	(27.7)	(17.6)
Accrued Taxes, Net	(0.3)	17.6
Other Current Assets	0.3	(0.2)
Other Current Liabilities	(10.9)	(10.7)
Net Cash Flows from (Used for) Operating Activities	(18.5)	32.4
Investing Activities
Construction Expenditures	(75.7)	(104.1)
Change in Advances to Affiliates, Net	0	72.2
Other Investing Activities	0.9	2.1
Net Cash Flows from (Used for) Investing Activities	(74.8)	(29.8)
Financing Activities
Change in Advances from Affiliates, Net	111.7	0
Retirement of Long-term Debt	(0.1)	(0.1)
Principal Payments for Capital Lease Obligations	(1.1)	(1)
Dividends Paid on Common Stock	(17.5)	0
Other Financing Activities	0.1	0.3
Net Cash Flows from (Used for) Financing Activities	93.1	(0.8)
Net Increase (Decrease) in Cash and Cash Equivalents	(0.2)	1.8
Cash and Cash Equivalents at Beginning of Period	1.5	1.4
Cash and Cash Equivalents at End of Period	1.3	3.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	15.9	15.1
Net Cash Paid (Received) for Income Taxes	(2.6)	(23.2)
Noncash Acquisitions Under Capital Leases	0.7	1.4
Construction Expenditures Included in Current Liabilities as of March 31,	22.3	35.7
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)	17.3	24.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	50.8	47.5
Deferred Income Taxes	43.1	44.6
Allowance for Equity Funds Used During Construction	(0.8)	(7.4)
Mark-to-Market of Risk Management Contracts	0.4	0.1
Property Taxes	(45.3)	(41.4)
Deferred Fuel Over/Under-Recovery, Net	(3.4)	3.7
Change in Other Noncurrent Assets	(0.6)	5.3
Change in Other Noncurrent Liabilities	(12.1)	(1.9)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	23.1	2.6
Fuel, Materials and Supplies	12.5	13.7
Accounts Payable	(33.5)	(19.9)
Accrued Taxes, Net	11.8	(13.2)
Accrued Interest	(20.3)	(20.8)
Other Current Assets	3.2	(1.7)
Other Current Liabilities	(19.1)	(28.2)
Net Cash Flows from (Used for) Operating Activities	27.1	7.5
Investing Activities
Construction Expenditures	(75.6)	(116.6)
Change in Advances to Affiliates, Net	167.8	0
Other Investing Activities	(4.4)	(7)
Net Cash Flows from (Used for) Investing Activities	87.8	(123.6)
Financing Activities
Change in Advances from Affiliates, Net	167.9	159.5
Retirement of Long-term Debt	(251.7)	(1.6)
Principal Payments for Capital Lease Obligations	(2.8)	(4.5)
Dividends Paid on Common Stock	(27.5)	(30)
Dividends Paid on Common Stock	(1.1)	(1.2)
Other Financing Activities	0.3	1
Net Cash Flows from (Used for) Financing Activities	(114.9)	123.2
Net Increase (Decrease) in Cash and Cash Equivalents	0	7.1
Cash and Cash Equivalents at Beginning of Period	10.3	5.2
Cash and Cash Equivalents at End of Period	10.3	12.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	50.6	47.7
Net Cash Paid (Received) for Income Taxes	0	14
Noncash Acquisitions Under Capital Leases	1.3	4.9
Construction Expenditures Included in Current Liabilities as of March 31,	$ 31.8	$ 83.7

Significant Accounting Matters

Significant Accounting Matters	3 Months Ended
	Mar. 31, 2017
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following table presents AEP’s basic and diluted EPS calculations included on the condensed statements of income: Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02 There were no antidilutive shares outstanding as of March 31, 2017 and 2016 .
Appalachian Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following table presents AEP’s basic and diluted EPS calculations included on the condensed statements of income: Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02 There were no antidilutive shares outstanding as of March 31, 2017 and 2016 .
Indiana Michigan Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following table presents AEP’s basic and diluted EPS calculations included on the condensed statements of income: Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02 There were no antidilutive shares outstanding as of March 31, 2017 and 2016 .
Ohio Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following table presents AEP’s basic and diluted EPS calculations included on the condensed statements of income: Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02 There were no antidilutive shares outstanding as of March 31, 2017 and 2016 .
Public Service Co Of Oklahoma [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following table presents AEP’s basic and diluted EPS calculations included on the condensed statements of income: Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02 There were no antidilutive shares outstanding as of March 31, 2017 and 2016 .
Southwestern Electric Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following table presents AEP’s basic and diluted EPS calculations included on the condensed statements of income: Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02 There were no antidilutive shares outstanding as of March 31, 2017 and 2016 .

New Accounting Pronouncements

New Accounting Pronouncements	3 Months Ended
	Mar. 31, 2017
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and continuing through the first quarter of 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and continuing through the first quarter of 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.
Appalachian Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and continuing through the first quarter of 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and continuing through the first quarter of 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.
Indiana Michigan Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and continuing through the first quarter of 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and continuing through the first quarter of 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.
Ohio Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and continuing through the first quarter of 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and continuing through the first quarter of 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.
Public Service Co Of Oklahoma [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and continuing through the first quarter of 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and continuing through the first quarter of 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.
Southwestern Electric Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and continuing through the first quarter of 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability, and will analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and continuing through the first quarter of 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2017-07 effective January 1, 2018.

Comprehensive Income

Comprehensive Income	3 Months Ended
	Mar. 31, 2017
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )
Appalachian Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )
Indiana Michigan Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )
Ohio Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )
Public Service Co Of Oklahoma [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )
Southwestern Electric Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three months ended March 31, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )

Rate Matters

Rate Matters	3 Months Ended
	Mar. 31, 2017
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7 OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of March 31, 2017 , AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of March 31, 2017 , AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the amended DIR caps. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for June 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for May 2017. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million . SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017. If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC. The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $36 million increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million , excluding AFUDC. As of March 31, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $630 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo) PJM Transmission Rates In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP East Transmission Companies Rates In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Appalachian Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7 OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of March 31, 2017 , AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of March 31, 2017 , AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the amended DIR caps. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for June 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for May 2017. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million . SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017. If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC. The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $36 million increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million , excluding AFUDC. As of March 31, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $630 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo) PJM Transmission Rates In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP East Transmission Companies Rates In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Indiana Michigan Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7 OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of March 31, 2017 , AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of March 31, 2017 , AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the amended DIR caps. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for June 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for May 2017. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million . SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017. If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC. The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $36 million increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million , excluding AFUDC. As of March 31, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $630 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo) PJM Transmission Rates In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP East Transmission Companies Rates In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Ohio Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7 OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of March 31, 2017 , AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of March 31, 2017 , AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the amended DIR caps. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for June 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for May 2017. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million . SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017. If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC. The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $36 million increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million , excluding AFUDC. As of March 31, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $630 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo) PJM Transmission Rates In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP East Transmission Companies Rates In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Public Service Co Of Oklahoma [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7 OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of March 31, 2017 , AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of March 31, 2017 , AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the amended DIR caps. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for June 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for May 2017. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million . SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017. If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC. The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $36 million increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million , excluding AFUDC. As of March 31, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $630 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo) PJM Transmission Rates In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP East Transmission Companies Rates In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Southwestern Electric Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2016 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2016 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2017 and updates the 2016 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing. I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7 OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of March 31, 2017 , AEP’s share of AEP Texas’ cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $581 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of March 31, 2017 , AEP’s share of ETT’s cumulative revenues from interim base rate increases from 2009 through 2016, subject to review, is estimated to be $636 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the amended DIR caps. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC PPA and stated that the stipulation agreement approved in 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for June 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. A hearing at the Texas District Court is scheduled for May 2017. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a base rate request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April 2017, various intervenors filed testimony with individual recommendations ranging from a slight net revenue reduction to a net $44 million revenue increase. The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $84 million . SWEPCO continues to evaluate this intervenor testimony. Staff testimony is scheduled to be filed in May 2017. A hearing at the PUCT is scheduled for June 2017. If any of these costs are not recoverable, including retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for September 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, SWEPCo filed its formula rate plan for test year 2015 with the LPSC. The filing included a $36 million annual increase, which will be effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $36 million increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could cost a total of approximately $850 million , excluding AFUDC. As of March 31, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, and had remaining contractual construction obligations of $10 million related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of March 31, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $630 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant, until these investments are included in base rates. The Louisiana jurisdictional share of Welsh Plant deferrals through March 31, 2017 were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a weighted average cost of capital (WACC) return on environmental investments and the related depreciation expense and taxes. SWEPCo has sought recovery of its project costs from retail customers at the state commissions and is recovering these costs from wholesale customers through their FERC-approved agreements. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters (Applies to AEP, APCo, I&M and OPCo) PJM Transmission Rates In June 2016, PJM transmission owners, including the AEP East Companies, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by various AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP East Transmission Companies Rates In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses, with a proposed effective date of January 1, 2017. The filing proposed that the rates would be implemented based upon the date provided in the resulting FERC order. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the AEP East Transmission Companies implemented the modified PJM OATT formula rates subject to refund which are based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2016 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , a $3 billion credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries, and a $500 million credit facility due in June 2018. As of March 31, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $345 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of March 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017 AEP has $110 million of variable rate Pollution Control Bonds supported by $111 million of bilateral letters of credit with maturities ranging from June 2017 to July 2017. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2017 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2017 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of March 31, 2017 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $82 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of March 31, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of March 31, 2017 , I&M’s accrual for all of these sites is $6 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the US Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. The district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement was reached in the three class actions and the district court issued preliminary approval of that settlement. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a settlement was reached in the remaining case. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. The entire case has been stayed pending resolution of the appeal. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Appalachian Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2016 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , a $3 billion credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries, and a $500 million credit facility due in June 2018. As of March 31, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $345 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of March 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017 AEP has $110 million of variable rate Pollution Control Bonds supported by $111 million of bilateral letters of credit with maturities ranging from June 2017 to July 2017. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2017 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2017 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of March 31, 2017 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $82 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of March 31, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of March 31, 2017 , I&M’s accrual for all of these sites is $6 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the US Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. The district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement was reached in the three class actions and the district court issued preliminary approval of that settlement. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a settlement was reached in the remaining case. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. The entire case has been stayed pending resolution of the appeal. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2016 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , a $3 billion credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries, and a $500 million credit facility due in June 2018. As of March 31, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $345 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of March 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017 AEP has $110 million of variable rate Pollution Control Bonds supported by $111 million of bilateral letters of credit with maturities ranging from June 2017 to July 2017. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2017 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2017 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of March 31, 2017 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $82 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of March 31, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of March 31, 2017 , I&M’s accrual for all of these sites is $6 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the US Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. The district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement was reached in the three class actions and the district court issued preliminary approval of that settlement. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a settlement was reached in the remaining case. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. The entire case has been stayed pending resolution of the appeal. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Ohio Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2016 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , a $3 billion credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries, and a $500 million credit facility due in June 2018. As of March 31, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $345 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of March 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017 AEP has $110 million of variable rate Pollution Control Bonds supported by $111 million of bilateral letters of credit with maturities ranging from June 2017 to July 2017. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2017 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2017 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of March 31, 2017 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $82 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of March 31, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of March 31, 2017 , I&M’s accrual for all of these sites is $6 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the US Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. The district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement was reached in the three class actions and the district court issued preliminary approval of that settlement. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a settlement was reached in the remaining case. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. The entire case has been stayed pending resolution of the appeal. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Public Service Co Of Oklahoma [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2016 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , a $3 billion credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries, and a $500 million credit facility due in June 2018. As of March 31, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $345 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of March 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017 AEP has $110 million of variable rate Pollution Control Bonds supported by $111 million of bilateral letters of credit with maturities ranging from June 2017 to July 2017. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2017 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2017 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of March 31, 2017 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $82 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of March 31, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of March 31, 2017 , I&M’s accrual for all of these sites is $6 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the US Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. The district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement was reached in the three class actions and the district court issued preliminary approval of that settlement. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a settlement was reached in the remaining case. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. The entire case has been stayed pending resolution of the appeal. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Southwestern Electric Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2016 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , a $3 billion credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries, and a $500 million credit facility due in June 2018. As of March 31, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $345 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of March 31, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017 AEP has $110 million of variable rate Pollution Control Bonds supported by $111 million of bilateral letters of credit with maturities ranging from June 2017 to July 2017. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of March 31, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of March 31, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2017 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $8 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2017 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of March 31, 2017 , assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of March 31, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $82 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of March 31, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of March 31, 2017 , I&M’s accrual for all of these sites is $6 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the US Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M has approached Westinghouse and expects to make a filing with the bankruptcy court to seek to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. AEGCo and I&M intend to file a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit. The district court dismissed plaintiffs’ claims seeking compensatory relief as premature. In addition, plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages. As a result, management is unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement was reached in the three class actions and the district court issued preliminary approval of that settlement. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a settlement was reached in the remaining case. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. The entire case has been stayed pending resolution of the appeal. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.

Impairment, Disposition and Ass

Impairment, Disposition and Assets and Liabilities Held for Sale	3 Months Ended
	Mar. 31, 2017
Impairment, Disposition and Assets and Liabilities Held for Sale	IMPAIRMENT, DISPOSITION AND ASSETS AND LIABILITIES HELD FOR SALE The disclosures in this note apply to AEP only. IMPAIRMENT Merchant Generating Assets (Generation & Marketing Segment) In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. In the first quarter of 2017, AEP recorded an additional pretax impairment of $4 million in Asset Impairments and Other Related Charges on AEP’s statements of income related to the Merchant Coal-fired Generation Assets. An additional $7 million pretax impairment recorded in Asset Impairments and Other Related Charges on AEP’s statements of income was related to the agreement to sell Zimmer Plant. The sale is further discussed in the “Assets and Liabilities Held for Sale” section of this note. DISPOSITION Gavin, Waterford, Darby, and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion , which were recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction are $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $227 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income. A coal purchase and sale agreement acquired by the nonaffiliated party is subject to an AEP guarantee in favor of the coal supplier, ensuring payments under the agreement until December 2017. The maximum potential amount of payments required under the guarantee was $34 million . ASSETS AND LIABILITIES HELD FOR SALE Zimmer, Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to a nonaffiliated party. The transaction is expected to close in the second quarter of 2017, subject to FERC approval. In the third quarter of 2016, management determined Gavin, Waterford, Darby and Lawrenceburg Plants met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. In the first quarter of 2017, management determined Zimmer Plant met the classification of held for sale. The assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of March 31, 2017 and as shown in the table below. The Income before Income Tax Expense and Equity Earnings of the five plants was approximately $47 million (excluding the $227 million pretax gain) and $112 million for the three months ended March 31, 2017 and 2016 , respectively. March 31, December 31, 2017 2016 Assets: (in millions) Fuel $ 6.9 $ 145.5 Materials and Supplies 0.1 49.4 Property, Plant and Equipment - Net 0.8 1,756.2 Other Class of Assets That Are Not Major 1.9 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 9.7 $ 1,951.2 Liabilities: Long-term Debt $ — $ 134.8 Waterford Plant Upgrade Liability — 52.2 Asset Retirement Obligations 1.9 36.7 Other Classes of Liabilities That Are Not Major 1.6 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 3.5 $ 235.9

Benefit Plans

Benefit Plans	3 Months Ended
	Mar. 31, 2017
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )
Appalachian Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )
Indiana Michigan Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )
Ohio Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )
Public Service Co Of Oklahoma [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )
Southwestern Electric Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )

Business Segments

Business Segments	3 Months Ended
	Mar. 31, 2017
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2017 and 2016 and reportable segment balance sheet information as of March 31, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ 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.
Appalachian Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2017 and 2016 and reportable segment balance sheet information as of March 31, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ 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.
Indiana Michigan Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2017 and 2016 and reportable segment balance sheet information as of March 31, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ 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.
Ohio Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2017 and 2016 and reportable segment balance sheet information as of March 31, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ 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.
Public Service Co Of Oklahoma [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2017 and 2016 and reportable segment balance sheet information as of March 31, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ 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.
Southwestern Electric Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three months ended March 31, 2017 and 2016 and reportable segment balance sheet information as of March 31, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ 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.

Derivatives and Hedging

Derivatives and Hedging	3 Months Ended
	Mar. 31, 2017
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 ) During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 , AEP did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges. During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of March 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered
Appalachian Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 ) During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 , AEP did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges. During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of March 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered
Indiana Michigan Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 ) During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 , AEP did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges. During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of March 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered
Ohio Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 ) During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 , AEP did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges. During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of March 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 ) During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 , AEP did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges. During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of March 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered
Southwestern Electric Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 ) During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 , AEP did not apply cash flow hedging to outstanding interest rate derivatives. During the three months ended March 31, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives as cash flow hedges. During the three months ended March 31, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of March 31, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 129 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2017
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8 The base cost of fixed income securities was $942 million and $938 million as of March 31, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $603 million and $592 million as of March 31, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8 The base cost of fixed income securities was $942 million and $938 million as of March 31, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $603 million and $592 million as of March 31, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8 The base cost of fixed income securities was $942 million and $938 million as of March 31, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $603 million and $592 million as of March 31, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8 The base cost of fixed income securities was $942 million and $938 million as of March 31, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $603 million and $592 million as of March 31, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8 The base cost of fixed income securities was $942 million and $938 million as of March 31, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $603 million and $592 million as of March 31, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments: March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8 The base cost of fixed income securities was $942 million and $938 million as of March 31, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $603 million and $592 million as of March 31, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2017 and 2016 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of March 31, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
Appalachian Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
Indiana Michigan Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
Ohio Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
Public Service Co Of Oklahoma [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
Southwestern Electric Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.

Financing Activities

Financing Activities	3 Months Ended
	Mar. 31, 2017
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first three months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3 In April 2017, Transource Energy issued $132 million of variable rate Other Long-term Debt due in 2020 . In April 2017, Transource Missouri retired its variable rate $131 million Other Long-term Debt due in 2018 . As of March 31, 2017 , trustees held, on behalf of AEP, $718 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $40 million and $345 million related to APCo, I&M and OPCo, respectively. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of March 31, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2017 are described in the following table: Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the three months ended March 31, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7 March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Appalachian Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first three months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3 In April 2017, Transource Energy issued $132 million of variable rate Other Long-term Debt due in 2020 . In April 2017, Transource Missouri retired its variable rate $131 million Other Long-term Debt due in 2018 . As of March 31, 2017 , trustees held, on behalf of AEP, $718 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $40 million and $345 million related to APCo, I&M and OPCo, respectively. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of March 31, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2017 are described in the following table: Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the three months ended March 31, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7 March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Indiana Michigan Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first three months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3 In April 2017, Transource Energy issued $132 million of variable rate Other Long-term Debt due in 2020 . In April 2017, Transource Missouri retired its variable rate $131 million Other Long-term Debt due in 2018 . As of March 31, 2017 , trustees held, on behalf of AEP, $718 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $40 million and $345 million related to APCo, I&M and OPCo, respectively. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of March 31, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2017 are described in the following table: Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the three months ended March 31, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7 March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Ohio Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first three months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3 In April 2017, Transource Energy issued $132 million of variable rate Other Long-term Debt due in 2020 . In April 2017, Transource Missouri retired its variable rate $131 million Other Long-term Debt due in 2018 . As of March 31, 2017 , trustees held, on behalf of AEP, $718 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $40 million and $345 million related to APCo, I&M and OPCo, respectively. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of March 31, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2017 are described in the following table: Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the three months ended March 31, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7 March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Public Service Co Of Oklahoma [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first three months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3 In April 2017, Transource Energy issued $132 million of variable rate Other Long-term Debt due in 2020 . In April 2017, Transource Missouri retired its variable rate $131 million Other Long-term Debt due in 2018 . As of March 31, 2017 , trustees held, on behalf of AEP, $718 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $40 million and $345 million related to APCo, I&M and OPCo, respectively. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of March 31, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2017 are described in the following table: Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the three months ended March 31, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7 March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Southwestern Electric Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first three months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3 In April 2017, Transource Energy issued $132 million of variable rate Other Long-term Debt due in 2020 . In April 2017, Transource Missouri retired its variable rate $131 million Other Long-term Debt due in 2018 . As of March 31, 2017 , trustees held, on behalf of AEP, $718 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $40 million and $345 million related to APCo, I&M and OPCo, respectively. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of March 31, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2017 are described in the following table: Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of March 31, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the three months ended March 31, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7 March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1

Significant Accounting Matters

Significant Accounting Matters (Policies)	3 Months Ended
	Mar. 31, 2017
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 .
Earnings Per Share	Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
Appalachian Power Co [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 .
Indiana Michigan Power Co [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 .
Ohio Power Co [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 .
Public Service Co Of Oklahoma [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 .
Southwestern Electric Power Co [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three months ended March 31, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 .

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	3 Months Ended
	Mar. 31, 2017
Derivatives and Hedging	Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Appalachian Power Co [Member]
Derivatives and Hedging	Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. 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. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Indiana Michigan Power Co [Member]
Derivatives and Hedging	Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Ohio Power Co [Member]
Derivatives and Hedging	Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles.
Southwestern Electric Power Co [Member]
Derivatives and Hedging	Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s 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. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	3 Months Ended
	Mar. 31, 2017
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.
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.
Appalachian Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Indiana Michigan Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.
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.
Ohio Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Public Service Co Of Oklahoma [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Southwestern Electric Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. 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 AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes (Policies)

Income Taxes (Policies)	3 Months Ended
	Mar. 31, 2017
Income Tax Policy	AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Appalachian Power Co [Member]
Income Tax Policy	AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Indiana Michigan Power Co [Member]
Income Tax Policy	AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Ohio Power Co [Member]
Income Tax Policy	AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Public Service Co Of Oklahoma [Member]
Income Tax Policy	AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Southwestern Electric Power Co [Member]
Income Tax Policy	AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Significant Accounting Matter25

Significant Accounting Matters (Tables)	3 Months Ended
	Mar. 31, 2017
Basic and Diluted EPS Calculations	Three Months Ended March 31, 2017 2016 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 592.2 $ 501.2 Weighted Average Number of Basic Shares Outstanding 491.7 $ 1.20 491.1 $ 1.02 Weighted Average Dilutive Effect of Stock-Based Awards 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.0 $ 1.20 491.3 $ 1.02

Comprehensive Income (Tables)

Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2017
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (21.8 ) — 1.2 — (20.6 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 12.8 — — — 12.8 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.1 0.5 — 0.4 9.0 Income Tax (Expense) Credit 2.8 0.1 — 0.2 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.3 0.4 — 0.2 5.9 Net Current Period Other Comprehensive Income (Loss) (16.5 ) 0.4 1.2 0.2 (14.7 ) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (8.1 ) — 0.6 — (7.5 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (8.6 ) — — — (8.6 ) Purchased Electricity for Resale 9.2 — — — 9.2 Interest Expense — 0.5 — — 0.5 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 0.5 — 0.2 1.3 Income Tax (Expense) Credit 0.2 0.2 — 0.1 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 0.3 — 0.1 0.8 Net Current Period Other Comprehensive Income (Loss) (7.7 ) 0.3 0.6 0.1 (6.7 ) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 )
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 )
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 )
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 2.8 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of March 31, 2016 $ 3.9
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2017 $ 3.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of March 31, 2016 $ 4.0
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended March 31, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.5 (0.2 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.5 (0.2 ) 0.3 Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 )

Rate Matters (Tables)

Rate Matters (Tables)	3 Months Ended
	Mar. 31, 2017
Regulatory Assets Pending Final Regulatory Approval	AEP March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 199.6 $ 159.9 Storm Related Costs 24.8 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.4 1.3 Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 36.3 Storm Related Costs 35.8 25.9 Environmental Control Projects 31.2 24.1 Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Cook Plant Turbine 13.5 12.8 Other Regulatory Assets Pending Final Regulatory Approval 29.0 29.3 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 410.3 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. (b) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.
Appalachian Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	APCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 39.3 $ 39.3 (a) As of March 31, 2017 , APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.
Indiana Michigan Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	I&M March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 13.5 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 10.0 8.1 Rockport Dry Sorbent Injection System - Indiana 7.5 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 68.3 $ 64.7
Ohio Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	OPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return gridSMART ® Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8
Public Service Co Of Oklahoma [Member]
Regulatory Assets Pending Final Regulatory Approval	PSO March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 124.2 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm Related Costs 29.9 20.0 Environmental Control Projects 16.5 13.1 Total Regulatory Assets Pending Final Regulatory Approval $ 171.1 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.
Southwestern Electric Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	SWEPCo March 31, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.8 Regulatory Assets Currently Not Earning a Return Environmental Control Projects 14.7 11.0 Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.0 2.7 Rate Case Expense - Texas 1.3 1.0 Other Regulatory Assets Pending Final Regulatory Approval 2.0 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 100.5 $ 95.9

Commitments, Guarantees and C28

Commitments, Guarantees and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2017
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6
Appalachian Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6
Indiana Michigan Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6
Ohio Power Co [Member]
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 174.4 April 2017 to March 2018 OPCo 0.6 September 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6
Public Service Co Of Oklahoma [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6
Southwestern Electric Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 37.8 APCo 5.7 I&M 3.2 OPCo 5.9 PSO 3.1 SWEPCo 3.6

Impairment, Disposition and A29

Impairment, Disposition and Assets and Liabilities Held for Sale (Tables)	3 Months Ended
	Mar. 31, 2017
Generation And Marketing [Member]
Assets and Liabilities Held for Sale	March 31, December 31, 2017 2016 Assets: (in millions) Fuel $ 6.9 $ 145.5 Materials and Supplies 0.1 49.4 Property, Plant and Equipment - Net 0.8 1,756.2 Other Class of Assets That Are Not Major 1.9 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 9.7 $ 1,951.2 Liabilities: Long-term Debt $ — $ 134.8 Waterford Plant Upgrade Liability — 52.2 Asset Retirement Obligations 1.9 36.7 Other Classes of Liabilities That Are Not Major 1.6 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 3.5 $ 235.9

Benefit Plans (Tables)

Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2017
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.8 52.9 14.8 15.2 Expected Return on Plan Assets (71.2 ) (70.1 ) (25.3 ) (26.8 ) Amortization of Prior Service Cost (Credit) 0.3 0.6 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 20.7 21.0 9.2 7.9 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 )
Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.0 $ 0.3 $ 0.2 Interest Cost 6.4 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 )
Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.0 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.8 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.3 ) (2.4 ) Amortization of Net Actuarial Loss 2.4 2.5 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.2 ) $ (2.5 )
Ohio Power Co [Member]
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.6 $ 0.2 $ 0.2 Interest Cost 4.8 5.2 1.7 1.7 Expected Return on Plan Assets (7.0 ) (6.9 ) (3.0 ) (3.2 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.0 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 )
Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.9 ) (1.4 ) (1.5 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.4 Net Periodic Benefit Cost (Credit) $ 1.5 $ 1.6 $ (1.0 ) $ (1.2 )
Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended March 31, Three Months Ended March 31, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.1 ) (1.6 ) (1.7 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 )

Business Segments (Tables)

Business Segments (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,269.8 $ 1,066.4 $ 27.7 $ 558.8 $ 10.6 $ — $ 3,933.3 Other Operating Segments 20.6 20.0 128.4 32.6 15.9 (217.5 ) — Total Revenues $ 2,290.4 $ 1,086.4 $ 156.1 $ 591.4 $ 26.5 $ (217.5 ) $ 3,933.3 Net Income (Loss) $ 220.5 $ 119.1 $ 72.8 $ 186.2 $ (4.4 ) $ — $ 594.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,218.1 $ 1,077.3 $ 29.3 $ 713.9 $ 6.3 $ — $ 4,044.9 Other Operating Segments 27.5 19.5 59.3 34.1 18.1 (158.5 ) — Total Revenues $ 2,245.6 $ 1,096.8 $ 88.6 $ 748.0 $ 24.4 $ (158.5 ) $ 4,044.9 Net Income $ 278.7 $ 107.5 $ 44.7 $ 70.7 $ 1.5 $ — $ 503.1 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) March 31, 2017 Total Property, Plant and Equipment $ 41,780.5 $ 14,990.4 $ 5,665.4 $ 483.7 $ 357.2 $ (366.7 ) (b) $ 62,910.5 Accumulated Depreciation and Amortization 12,712.9 3,697.8 120.7 140.4 188.7 (186.3 ) (b) 16,674.2 Total Property Plant and Equipment - Net $ 29,067.6 $ 11,292.6 $ 5,544.7 $ 343.3 $ 168.5 $ (180.4 ) (b) $ 46,236.3 Assets Held for Sale $ — $ — $ — $ 9.7 $ — $ — $ 9.7 Total Assets $ 37,562.2 $ 14,813.5 $ 6,721.4 $ 2,194.9 $ 21,233.1 $ (20,796.8 ) (b) (c) $ 61,728.3 Long-term Debt Due Within One Year: Non-Affiliated $ 1,518.9 $ 316.4 $ 130.7 $ 0.1 $ 548.1 $ — $ 2,514.2 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 9,938.9 4,554.4 1,931.4 — 297.5 — 16,722.2 Total Long-term Debt $ 11,497.8 $ 4,870.8 $ 2,062.1 $ 32.3 $ 845.6 $ (72.2 ) $ 19,236.4 Liabilities Held for Sale $ — $ — $ — $ 3.5 $ — $ — $ 3.5 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	3 Months Ended
	Mar. 31, 2017
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 245.8 $ 16.2 $ — $ 262.0 $ (177.0 ) $ 85.0 Long-term Risk Management Assets 361.7 4.9 — 366.6 (56.1 ) 310.5 Total Assets 607.5 21.1 — 628.6 (233.1 ) 395.5 Current Risk Management Liabilities 232.9 10.8 — 243.7 (175.5 ) 68.2 Long-term Risk Management Liabilities 346.0 70.9 1.9 418.8 (74.0 ) 344.8 Total Liabilities 578.9 81.7 1.9 662.5 (249.5 ) 413.0 Total MTM Derivative Contract Net Assets (Liabilities) $ 28.6 $ (60.6 ) $ (1.9 ) $ (33.9 ) $ 16.4 $ (17.5 ) AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Gain (Loss) on Hedging Instruments	Three Months Ended March 31, 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (0.5 ) $ 3.5 Gain (Loss) on Fair Value Portion of Long-term Debt 0.5 (3.5 )
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on AEP’s Balance Sheets March 31, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 13.0 $ — $ 11.2 $ — Hedging Liabilities (a) 73.6 — 46.7 — AOCI Loss Net of Tax (39.6 ) (15.3 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 3.3 (1.0 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	March 31, 2017 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 287.1 $ 6.5 $ 267.4 APCo — — — I&M — — — December 31, 2016 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Appalachian Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	APCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 19.2 $ (18.1 ) $ 1.1 Long-term Risk Management Assets 5.7 (5.5 ) 0.2 Total Assets 24.9 (23.6 ) 1.3 Current Risk Management Liabilities 24.7 (18.1 ) 6.6 Long-term Risk Management Liabilities 5.9 (5.8 ) 0.1 Total Liabilities 30.6 (23.9 ) 6.7 Total MTM Derivative Contract Net Assets (Liabilities) $ (5.7 ) $ 0.3 $ (5.4 ) APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 )
Collateral Required Under Various Triggering Events	March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	March 31, 2017 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 287.1 $ 6.5 $ 267.4 APCo — — — I&M — — — December 31, 2016 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Indiana Michigan Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	I&M Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 16.7 $ (14.3 ) $ 2.4 Long-term Risk Management Assets 3.9 (3.3 ) 0.6 Total Assets 20.6 (17.6 ) 3.0 Current Risk Management Liabilities 17.1 (14.3 ) 2.8 Long-term Risk Management Liabilities 3.6 (3.5 ) 0.1 Total Liabilities 20.7 (17.8 ) 2.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.1 ) $ 0.2 $ 0.1 I&M Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 )
Collateral Required Under Various Triggering Events	March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	March 31, 2017 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 287.1 $ 6.5 $ 267.4 APCo — — — I&M — — — December 31, 2016 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Ohio Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	OPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.1 $ — $ 0.1 Long-term Risk Management Assets — — — Total Assets 0.1 — 0.1 Current Risk Management Liabilities 6.3 — 6.3 Long-term Risk Management Liabilities 118.3 — 118.3 Total Liabilities 124.6 — 124.6 Total MTM Derivative Contract Net Liabilities $ (124.5 ) $ — $ (124.5 ) OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 )
Public Service Co Of Oklahoma [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	PSO Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.5 $ — $ 0.5 Long-term Risk Management Assets — — — Total Assets 0.5 — 0.5 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 0.5 $ — $ 0.5 PSO Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 )
Collateral Required Under Various Triggering Events	March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Southwestern Electric Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments March 31, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 301.0 33.1 18.9 10.9 4.6 5.5 Coal Tons 1.4 — 0.7 — — 0.7 Natural Gas MMBtus 24.3 — — — — — Heating Oil and Gasoline Gallons 5.4 1.0 0.5 1.2 0.6 0.6 Interest Rate USD $ 70.3 $ — $ — $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	March 31, 2017 December 31, 2016 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.5 $ 21.9 $ 7.9 $ 7.6 APCo — 0.3 0.5 0.7 I&M — 0.2 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	SWEPCo Fair Value of Derivative Instruments March 31, 2017 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (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 0.4 — 0.4 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 — 0.4 Total MTM Derivative Contract Net Assets $ 0.2 $ — $ 0.2 SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 5.5 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.5 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — 0.4 5.2 — — 0.1 Purchased Electricity for Resale 2.4 0.8 0.1 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.2 — — — — — Regulatory Assets (b) (14.9 ) (5.8 ) (0.2 ) (8.6 ) — (0.2 ) Regulatory Liabilities (b) 25.2 10.9 6.8 — 2.4 4.6 Total Gain (Loss) on Risk Management Contracts $ 29.1 $ 6.3 $ 11.9 $ (8.6 ) $ 2.4 $ 4.5 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended March 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.6 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (3.5 ) — — — — — Generation & Marketing Revenues 19.8 — — — — — Electric Generation, Transmission and Distribution Revenues (a) — (0.8 ) 1.6 (3.5 ) — — Sales to AEP Affiliates — 1.1 4.0 — — — Purchased Electricity for Resale 2.1 1.4 0.1 — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (b) (11.1 ) 0.2 0.3 (11.4 ) (0.5 ) 0.1 Regulatory Liabilities (b) 12.7 15.9 3.9 (15.2 ) — 4.5 Total Gain (Loss) on Risk Management Contracts $ 19.1 $ 17.5 $ 9.7 $ (30.3 ) $ (0.7 ) $ 4.4 (a) Amounts for OPCo represents Electricity, Transmission and Distribution. (b) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets March 31, 2017 December 31, 2016 Interest Rate Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months (in millions) APCo $ 2.7 $ 0.7 $ 2.9 $ 0.7 I&M (11.7 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.8 1.1 3.0 1.1 PSO 3.2 0.8 3.4 0.8 SWEPCo (6.9 ) (1.4 ) (7.4 ) (1.4 )
Collateral Required Under Various Triggering Events	March 31, 2017 December 31, 2016 Company Amount of Collateral That Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts Amount of Collateral Amount of (in millions) AEP $ 35.2 $ 197.2 (a) $ 9.3 $ 280.3 (a) APCo 6.7 — 1.0 — I&M 3.9 — 0.6 — PSO 5.1 3.2 2.1 3.2 SWEPCo 6.1 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Book Values and Fair Values of Long-term Debt	March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
Other Temporary Investments	March 31, 2017 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 152.7 $ — $ — $ 152.7 Fixed Income Securities – Mutual Funds (b) 93.1 — (0.8 ) 92.3 Equity Securities – Mutual Funds 14.5 15.5 — 30.0 Total Other Temporary Investments $ 260.3 $ 15.5 $ (0.8 ) $ 275.0 December 31, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
Debt and Equity Securities Within Other Temporary Investments	Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — Purchases of Investments 0.5 0.4 Gross Realized Gains on Investment Sales — — Gross Realized Losses on Investment Sales — —
Nuclear Trust Fund Investments	March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3
Fair Value, Assets and Liabilities Measured on Recurring Basis	AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 166.1 $ 175.0 Other Temporary Investments Restricted Cash (a) 136.2 1.3 — 15.2 152.7 Fixed Income Securities – Mutual Funds 92.3 — — — 92.3 Equity Securities – Mutual Funds (b) 30.0 — — — 30.0 Total Other Temporary Investments 258.5 1.3 — 15.2 275.0 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.8 353.3 204.3 (176.9 ) 382.5 Cash Flow Hedges: Commodity Hedges (c) — 13.7 1.1 (1.8 ) 13.0 Total Risk Management Assets 1.8 367.0 205.4 (178.7 ) 395.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities – Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,621.4 $ 1,341.6 $ 205.4 $ 10.3 $ 3,178.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 5.4 $ 340.6 $ 184.8 $ (193.3 ) $ 337.5 Cash Flow Hedges: Commodity Hedges (c) — 36.3 39.1 (1.8 ) 73.6 Fair Value Hedges — 1.9 — — 1.9 Total Risk Management Liabilities $ 5.4 $ 378.8 $ 223.9 $ (195.1 ) $ 413.0 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs March 31, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 199.5 $ 213.5 Discounted Cash Flow Forward Market Price (a) $ 9.65 $ 92.72 $ 38.24 Counterparty Credit Risk (b) 17 691 259 FTRs 5.9 10.4 Discounted Cash Flow Forward Market Price (a) (5.46 ) 7.22 0.50 Total $ 205.4 $ 223.9 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Book Values and Fair Values of Long-term Debt	March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.0 $ — $ — $ 0.1 $ 8.1 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 16.6 2.0 (17.3 ) 1.3 Total Assets $ 8.0 $ 16.6 $ 2.0 $ (17.2 ) $ 9.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.5 $ 7.8 $ (17.6 ) $ 6.7 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs March 31, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.4 7.6 Discounted Cash Flow Forward Market Price 0.04 4.14 1.34 Total $ 2.0 $ 7.8 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long-term Debt	March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
Nuclear Trust Fund Investments	March 31, 2017 December 31, 2016 Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments Fair Value Gross Unrealized Gains Other-Than-Temporary Impairments (in millions) Cash and Cash Equivalents $ 16.6 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 814.2 28.4 (4.6 ) 785.4 27.1 (5.5 ) Corporate Debt 57.2 2.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 101.9 0.2 (1.0 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 973.3 31.1 (6.8 ) 967.4 29.8 (7.6 ) Equity Securities – Domestic 1,343.3 740.6 (78.9 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,333.2 $ 771.7 $ (85.7 ) $ 2,256.2 $ 707.7 $ (87.2 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended March 31, 2017 2016 (in millions) Proceeds from Investment Sales $ 487.9 $ 1,137.7 Purchases of Investments 505.5 1,151.6 Gross Realized Gains on Investment Sales 11.3 15.8 Gross Realized Losses on Investment Sales 8.1 7.8
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 221.8 1 year – 5 years 346.3 5 years – 10 years 192.8 After 10 years 212.4 Total $ 973.3
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 14.6 $ 2.2 $ (13.8 ) $ 3.0 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 8.9 — — 7.7 16.6 Fixed Income Securities: United States Government — 814.2 — — 814.2 Corporate Debt — 57.2 — — 57.2 State and Local Government — 101.9 — — 101.9 Subtotal Fixed Income Securities — 973.3 — — 973.3 Equity Securities - Domestic (b) 1,343.3 — — — 1,343.3 Total Spent Nuclear Fuel and Decommissioning Trusts 1,352.2 973.3 — 7.7 2,333.2 Total Assets $ 1,352.2 $ 987.9 $ 2.2 $ (6.1 ) $ 2,336.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.7 $ 0.2 $ (14.0 ) $ 2.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs March 31, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.1 Discounted Cash Flow Forward Market Price $ 19.36 $ 46.45 $ 34.61 FTRs 1.9 0.1 Discounted Cash Flow Forward Market Price (0.33 ) 3.70 1.75 Total $ 2.2 $ 0.2 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Book Values and Fair Values of Long-term Debt	March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.0 $ — $ — $ — $ 16.0 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — — 0.1 Total Assets $ 16.0 $ 0.1 $ — $ — $ 16.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 124.6 $ — $ 124.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs March 31, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 124.6 Discounted Cash Flow Forward Market Price (a) $ 28.17 $ 70.98 $ 46.04 Counterparty Credit Risk (b) 34 327 245 Total $ — $ 124.6 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long-term Debt	March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.5 $ (0.1 ) $ 0.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs March 31, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.5 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long-term Debt	March 31, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,236.4 $ 21,239.5 $ 20,391.2 (a) $ 22,211.9 (a) APCo 3,918.8 4,558.8 4,033.9 4,613.2 I&M 2,439.5 2,646.8 2,471.4 2,661.6 OPCo 1,742.0 2,070.8 1,763.9 2,092.5 PSO 1,286.1 1,431.1 1,286.0 1,419.0 SWEPCo 2,427.7 2,591.2 2,679.1 2,814.3 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis March 31, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.9 $ — $ — $ 1.4 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 0.6 (0.1 ) 0.6 Total Assets $ 8.9 $ 0.1 $ 0.6 $ 1.3 $ 10.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.1 $ (0.1 ) $ 0.4 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended March 31, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.8 5.7 2.0 (0.5 ) 2.2 4.5 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 16.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (17.2 ) — — — — — Settlements (28.8 ) (12.2 ) (4.3 ) 2.1 (2.6 ) (4.9 ) Transfers into Level 3 (d) (e) 5.2 — — — — — Transfers out of Level 3 (e) (8.3 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (5.8 ) (0.7 ) 1.5 (7.2 ) 0.1 0.2 Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Three Months Ended March 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 23.5 15.3 2.5 (0.6 ) (0.8 ) 4.6 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 21.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 1.3 — — — — — Settlements (42.7 ) (27.7 ) (4.6 ) 1.4 0.5 (4.9 ) Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (20.5 ) 3.2 1.4 (27.6 ) 0.3 0.2 Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs March 31, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ (3.51 ) $ 3.13 $ (0.40 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)

Financing Activities (Tables)

Financing Activities (Tables)	3 Months Ended
	Mar. 31, 2017
Long-term Debt	Type of Debt March 31, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,360.2 $ 14,761.0 Pollution Control Bonds 1,620.8 1,725.1 Notes Payable 293.2 326.9 Securitization Bonds 1,582.1 1,705.0 Spent Nuclear Fuel Obligation (a) 266.6 266.3 Other Long-term Debt 1,113.5 1,606.9 Total Long-term Debt Outstanding 19,236.4 20,391.2 Long-term Debt Due Within One Year 2,514.2 3,013.4 Long-term Debt $ 16,722.2 $ 17,377.8 (a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3
Short Term Debt	March 31, 2017 December 31, 2016 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 572.0 1.00 % $ 673.0 0.70 % Commercial Paper 964.0 1.27 % 1,040.0 1.02 % Total Short-term Debt $ 1,536.0 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Comparative Accounts Receivable Information	Three Months Ended March 31, 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.00 % 0.58 % Net Uncollectible Accounts Receivable Written Off $ 5.9 $ 5.7
Customer Accounts Receivable Managed Portfolio	March 31, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 872.6 $ 945.0 Short-term – Securitized Debt of Receivables 572.0 673.0 Delinquent Securitized Accounts Receivable 49.0 42.7 Bad Debt Reserves Related to Securitization 27.5 27.7 Unbilled Receivables Related to Securitization 253.6 322.1
Appalachian Power Co [Member]
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — %
Accounts Receivable and Accrued Unbilled Revenues	Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Indiana Michigan Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) I&M Pollution Control Bonds $ 25.0 Variable 2019 I&M Pollution Control Bonds 52.0 Variable 2021 Non-Registrant: Transource Missouri Other Long-term Debt 7.0 Variable 2018 Total Issuances $ 84.0 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — %
Accounts Receivable and Accrued Unbilled Revenues	Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Ohio Power Co [Member]
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — %
Accounts Receivable and Accrued Unbilled Revenues	Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Public Service Co Of Oklahoma [Member]
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — %
Accounts Receivable and Accrued Unbilled Revenues	Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Southwestern Electric Power Co [Member]
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 1.7 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 7.5 Variable 2019 I&M Notes Payable 7.9 Variable 2019 I&M Notes Payable 8.0 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 7.1 Variable 2021 I&M Other Long-term Debt 0.4 6.00 2025 OPCo Securitization Bonds 22.4 0.958 2018 PSO Other Long-term Debt 0.1 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 TCC Securitization Bonds 89.9 5.17 2018 Total Retirements and Principal Payments $ 1,242.3
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Company Maximum Borrowings from the Utility Money Pool Maximum Loans to the Utility Money Pool Average Borrowings from the Utility Money Pool Average Loans to the Utility Money Pool Net Borrowings from the Utility Money Pool as of March 31, 2017 Authorized Short-term Borrowing Limit (in millions) APCo $ 231.3 $ 24.1 $ 177.7 $ 23.9 $ 158.7 $ 600.0 I&M 291.9 12.5 234.9 12.5 274.3 500.0 OPCo 84.0 56.2 35.4 27.9 18.3 400.0 PSO 163.7 — 91.8 — 163.7 300.0 SWEPCo 187.5 178.6 139.5 169.5 167.9 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Three Months Ended March 31, 2017 2016 Maximum Interest Rate 1.27 % 0.83 % Minimum Interest Rate 0.92 % 0.69 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Three Months Ended March 31, Three Months Ended March 31, Company 2017 2016 2017 2016 APCo 1.04 % 0.73 % 1.03 % 0.73 % I&M 1.04 % 0.72 % 1.03 % 0.74 % OPCo 1.10 % — % 0.98 % 0.73 % PSO 1.06 % — % — % 0.72 % SWEPCo 1.06 % 0.73 % 0.98 % — %
Accounts Receivable and Accrued Unbilled Revenues	Company March 31, 2017 December 31, 2016 (in millions) APCo $ 131.4 $ 142.0 I&M 134.2 136.7 OPCo 367.6 388.3 PSO 99.4 110.4 SWEPCo 107.8 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 1.4 $ 1.8 I&M 1.5 1.9 OPCo 5.7 7.9 PSO 1.5 1.4 SWEPCo 1.6 1.5
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended March 31, Company 2017 2016 (in millions) APCo $ 369.7 $ 384.4 I&M 418.2 388.1 OPCo 632.3 646.6 PSO 286.8 272.1 SWEPCo 341.2 336.1
Nonutility Money Pool Activity [Table Text Block]	Maximum Average Loans to the Loans to the Loans to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool March 31, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool [Text Block]	Maximum Minimum Average Interest Rate Interest Rate Interest Rate Three for Funds Loaned for Funds Loaned for Funds Loaned Months Ended to the Nonutility to the Nonutility to the Nonutility March 31, Money Pool Money Pool Money Pool 2017 1.27 % 0.92 % 1.03 %

Significant Accounting Matter35

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Amounts Attributable to AEP Common Shareholders
Net Income (Loss) Available to Common Stockholders, Basic	$ 592.2	$ 501.2
Weighted Average Number of Basic AEP Common Shares Outstanding	491,712,042	491,108,392
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 1.20	$ 1.02
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding	492,031,975	491,332,305
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 1.20	$ 1.02
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Antidilutive Shares Outstanding	0	0
Southwestern Electric Power Co [Member]
Amounts Attributable to AEP Common Shareholders
Net Income (Loss) Available to Common Stockholders, Basic	$ 16.3	$ 23.4
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares	300,000	200,000
Dilutive Securities, Effect on Basic Earnings Per Share	$ 0	$ 0

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	$ (156.3)	$ (127.1)
Change in Fair Value Recognized in AOCI	(20.6)	(7.5)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	38.3	35.6
Purchased Electricity for Resale	769.6	731.4
Interest Expense	221.8	217
Reclassifications from AOCI, before Income Tax (Expense) Credit	9	1.3
Income Tax (Expense) Credit	(343.2)	(235.5)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	5.9	0.8
Net Current Period Other Comprehensive Income	(14.7)	(6.7)
Ending Balance in AOCI	(171)	(133.8)
Securities Available for Sale [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	8.4	7.1
Change in Fair Value Recognized in AOCI	1.2	0.6
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Net Current Period Other Comprehensive Income	1.2	0.6
Ending Balance in AOCI	9.6	7.7
Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(125.9)	(111.8)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.4	0.2
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.2	0.1
Net Current Period Other Comprehensive Income	0.2	0.1
Ending Balance in AOCI	(125.7)	(111.7)
Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(23.1)	(5.2)
Change in Fair Value Recognized in AOCI	(21.8)	(8.1)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	8.1	0.6
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	5.3	0.4
Net Current Period Other Comprehensive Income	(16.5)	(7.7)
Ending Balance in AOCI	(39.6)	(12.9)
Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(15.7)	(17.2)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.5
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.4	0.3
Net Current Period Other Comprehensive Income	0.4	0.3
Ending Balance in AOCI	(15.3)	(16.9)
Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	(4.7)	(8.6)
Purchased Electricity for Resale	12.8	9.2
Interest Expense	0.5	0.5
Amortization of Prior Service Cost (Credit)	(4.9)	(4.9)
Amortization of Actuarial (Gains)/Losses	5.3	5.1
Income Tax (Expense) Credit	3.1	0.5
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	0	0
Purchased Electricity for Resale	0	0
Interest Expense	0	0
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Actuarial (Gains)/Losses	0	0
Income Tax (Expense) Credit	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	0	0
Purchased Electricity for Resale	0	0
Interest Expense	0	0
Amortization of Prior Service Cost (Credit)	(4.9)	(4.9)
Amortization of Actuarial (Gains)/Losses	5.3	5.1
Income Tax (Expense) Credit	0.2	0.1
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	(4.7)	(8.6)
Purchased Electricity for Resale	12.8	9.2
Interest Expense	0	0
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Actuarial (Gains)/Losses	0	0
Income Tax (Expense) Credit	2.8	0.2
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	0	0
Purchased Electricity for Resale	0	0
Interest Expense	0.5	0.5
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Actuarial (Gains)/Losses	0	0
Income Tax (Expense) Credit	0.1	0.2
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(8.4)	(2.8)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	5.4	4.1
Purchased Electricity for Resale	90.8	108.2
Interest Expense	48.1	47
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.8)	(0.8)
Income Tax (Expense) Credit	(63.6)	(72.9)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.5)	(0.5)
Net Current Period Other Comprehensive Income	(0.5)	(0.5)
Ending Balance in AOCI	(8.9)	(3.3)
Appalachian Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(11.3)	(6.4)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.5)	(0.5)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.3)	(0.3)
Net Current Period Other Comprehensive Income	(0.3)	(0.3)
Ending Balance in AOCI	(11.6)	(6.7)
Appalachian Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	2.9	3.6
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.3)	(0.3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.2)	(0.2)
Net Current Period Other Comprehensive Income	(0.2)	(0.2)
Ending Balance in AOCI	2.7	3.4
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.3)	(0.3)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.2)
Amortization of Actuarial (Gains)/Losses	0.8	0.7
Income Tax (Expense) Credit	(0.3)	(0.3)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0	0
Amortization of Prior Service Cost (Credit)	(1.3)	(1.2)
Amortization of Actuarial (Gains)/Losses	0.8	0.7
Income Tax (Expense) Credit	(0.2)	(0.2)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.3)	(0.3)
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Actuarial (Gains)/Losses	0	0
Income Tax (Expense) Credit	(0.1)	(0.1)
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(16.2)	(16.7)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	3.3	5.5
Purchased Electricity for Resale	37.3	49.6
Interest Expense	27.7	22.5
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.5
Income Tax (Expense) Credit	(29.2)	(24.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.3	0.4
Net Current Period Other Comprehensive Income	0.3	0.4
Ending Balance in AOCI	(15.9)	(16.3)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(4.2)	(3.4)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Net Current Period Other Comprehensive Income	0	0
Ending Balance in AOCI	(4.2)	(3.4)
Indiana Michigan Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(12)	(13.3)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.5
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.3	0.4
Net Current Period Other Comprehensive Income	0.3	0.4
Ending Balance in AOCI	(11.7)	(12.9)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.5	0.5
Amortization of Prior Service Cost (Credit)	(0.2)	(0.2)
Amortization of Actuarial (Gains)/Losses	0.2	0.2
Income Tax (Expense) Credit	0.2	0.1
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0	0
Amortization of Prior Service Cost (Credit)	(0.2)	(0.2)
Amortization of Actuarial (Gains)/Losses	0.2	0.2
Income Tax (Expense) Credit	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.5	0.5
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Actuarial (Gains)/Losses	0	0
Income Tax (Expense) Credit	0.2	0.1
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	2	2.1
Purchased Electricity for Resale	188.3	164.9
Interest Expense	25	31.4
Income Tax (Expense) Credit	(46.3)	(37.5)
Net Current Period Other Comprehensive Income	(0.2)	(0.4)
Ending Balance in AOCI	2.8
Ohio Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3	4.3
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4)	(0.5)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.2)	(0.4)
Net Current Period Other Comprehensive Income	(0.2)	(0.4)
Ending Balance in AOCI	2.8	3.9
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.4)	(0.5)
Income Tax (Expense) Credit	(0.2)	(0.1)
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3.4
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	1.1	1.5
Purchased Electricity for Resale	125.3	93.3
Interest Expense	13.6	14.4
Income Tax (Expense) Credit	(2.9)	(8.2)
Net Current Period Other Comprehensive Income	(0.2)	(0.2)
Ending Balance in AOCI	3.2
Public Service Co Of Oklahoma [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3.4	4.2
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.3)	(0.3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.2)	(0.2)
Net Current Period Other Comprehensive Income	(0.2)	(0.2)
Ending Balance in AOCI	3.2	4
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.3)	(0.3)
Income Tax (Expense) Credit	(0.1)	(0.1)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(9.4)	(9.4)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Generation & Marketing Revenues	0.4	0.5
Purchased Electricity for Resale	32.4	28.1
Interest Expense	29.9	27.9
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.4	0.4
Income Tax (Expense) Credit	(9.5)	(7.4)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.3	0.3
Net Current Period Other Comprehensive Income	0.3	0.3
Ending Balance in AOCI	(9.1)	(9.1)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(2)	(0.3)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.3)	(0.3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.2)	(0.2)
Net Current Period Other Comprehensive Income	(0.2)	(0.2)
Ending Balance in AOCI	(2.2)	(0.5)
Southwestern Electric Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(7.4)	(9.1)
Change in Fair Value Recognized in AOCI	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.7	0.7
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.5	0.5
Net Current Period Other Comprehensive Income	0.5	0.5
Ending Balance in AOCI	(6.9)	(8.6)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.7	0.7
Amortization of Prior Service Cost (Credit)	(0.5)	(0.5)
Amortization of Actuarial (Gains)/Losses	0.2	0.2
Income Tax (Expense) Credit	0.1	0.1
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0	0
Amortization of Prior Service Cost (Credit)	(0.5)	(0.5)
Amortization of Actuarial (Gains)/Losses	0.2	0.2
Income Tax (Expense) Credit	(0.1)	(0.1)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.7	0.7
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Actuarial (Gains)/Losses	0	0
Income Tax (Expense) Credit	$ 0.2	$ 0.2

Rate Matters - Regulatory Asset

Rate Matters - Regulatory Assets (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		$ 5,583.1	$ 5,625.5
Accumulated Depreciation and Amortization		16,674.2	16,397.3
Construction in Progress		3,196.8	3,183.9
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1,111.4	1,121.1
Accumulated Depreciation and Amortization		3,705.4	3,636.8
Construction in Progress		386.1	390.3
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		906.1	916.6
Accumulated Depreciation and Amortization		2,984.1	3,005.1
Construction in Progress		521	654.2
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1,079.8	1,107.5
Accumulated Depreciation and Amortization		2,140	2,116
Construction in Progress		243.4	221.5
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		381.1	340.2
Accumulated Depreciation and Amortization		1,338.3	1,272.7
Construction in Progress		106.3	148.2
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		559.1	551.2
Accumulated Depreciation and Amortization		2,608	2,567.1
Construction in Progress		125.2	113.8
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[1]	410.3	450.1
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[1]	39.3	39.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		68.3	64.7
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	100.8
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		171.1	118.1
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		100.5	95.9
Asset Retirement Obligation - Arkansas, Louisiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		3	2.7
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		13.5	12.8
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		13.5	12.8
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		36.3	36.3
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		36.3	36.3
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		10	8.1
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		31.2	24.1
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		16.5	13.1
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		14.7	11
Gridsmart Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	4.1
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	96.7
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0	96.7
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1.4	1.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.5	0.5
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.8	0.8
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		29	29.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		0.6	0.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1	0.9
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		2	1.9
Plant Retirement Costs - Asset Retirement Obligation Costs | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		29.6	29.6
Plant Retirement Costs - Asset Retirement Obligation Costs | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		29.6	29.6
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		9.1	9.1
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		9.1	9.1
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[2]	199.6	159.9
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	[2]	124.2	84.5
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		75.4	75.4
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		1.3	1
Rockport Plant Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		7.5	6.6
Shipe Road Transmission Project - FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		3.3	3.1
Storm Related Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		24.8	25.1
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		35.8	25.9
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent		$ 29.9	$ 20
[1]	As of March 31, 2017, APCo has also recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. The remaining Virginia net book value will be considered in APCo’s next depreciation study and be recovered through an increase in its Virginia depreciation rates beginning in the first quarter of 2021, as part of its 2018-2019 Virginia biennial March 2020 filing.
[2]	In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3.

Rate Matters - East Companies

Rate Matters - East Companies (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)MW
FERC Transmission Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	10.99%
Intervenor Recommended Return On Common Equity	8.32%
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	10.20%
PUCO Approved Reduced Customer Credits | $	$ 15
Solar Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW	400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW	500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement	100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement	50.00%
Return on Common Equity Proposed in the Amended ESP Filing	10.41%
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	10.20%
PUCO Approved Reduced Customer Credits | $	$ 15
Solar Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW	400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW	500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement	100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement	50.00%
Return on Common Equity Proposed in the Amended ESP Filing	10.41%
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs | $	$ 274
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs | $	$ 274

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Apr. 27, 2017	Mar. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 3,196.8	$ 3,183.9
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		106.3	148.2
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		125.2	$ 113.8
AEP Texas Interim Transmission and Distribution Rates [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		$ 581
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Ownership Interest In ETT		50.00%
AEP Share Of ETT Cumulative Revenues Subject To Review		$ 636
Louisiana 2015 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14
Louisiana 2015 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 14
Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		$ 850
Construction Work in Progress		398
Remaining Contractual Construction Obligations		10
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		11
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		6
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		850
Construction Work in Progress		398
Remaining Contractual Construction Obligations		10
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		11
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		6
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		630
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		630
2012 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114
Resulting Approved Base Rate Increase		52
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114
Resulting Approved Base Rate Increase		52
2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Net Increase in Texas Annual Revenues		$ 69
Requested Return on Common Equity		10.00%
Amount Of Increase Related To Environmental Controls		$ 34
Amount of Increase Related to Additonal Investment and Increased Operating Costs		25
Amount of Increase Related to Transmission Cost Recovery		8
Amount of Increase Related to Vegetation Management		$ 2
Texas Jurisdictional Share of the Welsh Plant		33.00%
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Net Increase in Texas Annual Revenues		$ 69
Requested Return on Common Equity		10.00%
Amount Of Increase Related To Environmental Controls		$ 34
Amount of Increase Related to Additonal Investment and Increased Operating Costs		25
Amount of Increase Related to Transmission Cost Recovery		8
Amount of Increase Related to Vegetation Management		$ 2
Texas Jurisdictional Share of the Welsh Plant		33.00%
Subsequent Event [Member] | Louisiana 2017 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	$ 36
Subsequent Event [Member] | Louisiana 2017 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	36
Subsequent Event [Member] | 2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Net Increase in Texas Annual Revenues	44
Recommended Investment Disallowances Resulting in Possible Write-Offs	84
Subsequent Event [Member] | 2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Net Increase in Texas Annual Revenues	44
Recommended Investment Disallowances Resulting in Possible Write-Offs	$ 84
Subsequent Event [Member] | Minimum [Member] | 2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Return on Equity	9.20%
Subsequent Event [Member] | Minimum [Member] | 2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Return on Equity	9.20%
Subsequent Event [Member] | Maximum [Member] | 2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Return on Equity	9.35%
Subsequent Event [Member] | Maximum [Member] | 2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Return on Equity	9.35%

Commitments, Guarantees and C40

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	$ 174.4
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	110
Bilateral Letters of Credit, Matured	111
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	3,500
Letters of Credit Limit	1,200
Uncommitted Facility	345
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	115
Estimated Final Cost Mine Reclamation	74
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	70
Amount Collected, Rider Mine Close Other Assets Noncurrent	4
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	74
Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	37.8
Guarantees of Equity Method Investees [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Amount of Future Payments Associated with Guarantee		$ 75
Appalachian Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	5.7
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3.2
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	0.6
Ohio Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	5.9
Public Service Co Of Oklahoma [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3.1
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	115
Estimated Final Cost Mine Reclamation	74
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	70
Amount Collected, Rider Mine Close Other Assets Noncurrent	4
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	74
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3.6
Superfund and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision	6
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision	6
Railcar Lease [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars	$ 8
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term	83.00%
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee of Return-and-Sale Option	$ 8
Railcar Lease [Member] | Southwestern Electric Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars	$ 10
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term	83.00%
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee of Return-and-Sale Option	$ 10
Boat and Barge Leases [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases	82
Total Guarantee Obligation	12
Current Guarantee Obligation	2
Noncurrent Guarantee Obligation	10
June 2021 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	3,000
June 2018 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	500
October 2017 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Uncommitted Facility	75
April 2019 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Uncommitted Facility	$ 100

Impairment, Disposition and A41

Impairment, Disposition and Assets and Liabilities Held for Sale (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Other Asset Impairment Charges	$ 11.2	$ 0
Assets Held for Sale	9.7		$ 1,951.2
Liabilities Held for Sale	3.5		235.9
Generation And Marketing [Member]
Cash Proceeds from Sale of Plants Gross	2,200
Cash Proceeds from Disposition of Plants, Net	1,200
Pre-tax Gain on Sale of Plants	227
Maximum Potential Loss Related to Guarantee	34
Income from Continuing Operations before Income Tax Expense and Equity Earnings of the Plants Sold	47	$ 112
Fuel	6.9		145.5
Materials and Supplies	0.1		49.4
Property, Plant and Equipment - Net	0.8		1,756.2
Other Classes of Assets That Are Not Major	1.9		0.1
Assets Held for Sale	9.7		1,951.2
Long-term Debt	0		134.8
Waterford Plant Upgrade Liability	0		52.2
Asset Retirement Obligations	1.9		36.7
Other Classes of Liabilities That Are Not Major	1.6		12.2
Liabilities Held for Sale	3.5		$ 235.9
Merchant Coal-Fired Generation Assets [Member] | Generation And Marketing [Member]
Other Asset Impairment Charges	4
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Merchant Coal-Fired Generation Assets [Member] | Generation And Marketing [Member]
Other Asset Impairment Charges	$ 7

Benefit Plans (Details)

Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 24.1	$ 21.4
Interest Cost	50.8	52.9
Expected Return on Plan Assets	(71.2)	(70.1)
Amortization of Prior Service Cost (Credit)	0.3	0.6
Amortization of Net Actuarial Loss	20.7	21
Net Periodic Benefit Cost (Credit)	24.7	25.8
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.3	2
Interest Cost	6.4	6.8
Expected Return on Plan Assets	(8.9)	(8.8)
Amortization of Prior Service Cost (Credit)	0.1	0
Amortization of Net Actuarial Loss	2.6	2.7
Net Periodic Benefit Cost (Credit)	2.5	2.7
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3.5	3
Interest Cost	6.1	6.3
Expected Return on Plan Assets	(8.6)	(8.4)
Amortization of Prior Service Cost (Credit)	0	0.1
Amortization of Net Actuarial Loss	2.4	2.5
Net Periodic Benefit Cost (Credit)	3.4	3.5
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.9	1.6
Interest Cost	4.8	5.2
Expected Return on Plan Assets	(7)	(6.9)
Amortization of Prior Service Cost (Credit)	0	0
Amortization of Net Actuarial Loss	2	2
Net Periodic Benefit Cost (Credit)	1.7	1.9
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.6	1.5
Interest Cost	2.7	2.8
Expected Return on Plan Assets	(3.9)	(3.9)
Amortization of Prior Service Cost (Credit)	0	0.1
Amortization of Net Actuarial Loss	1.1	1.1
Net Periodic Benefit Cost (Credit)	1.5	1.6
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.2	2
Interest Cost	3.1	3.1
Expected Return on Plan Assets	(4.2)	(4.1)
Amortization of Prior Service Cost (Credit)	0	0.1
Amortization of Net Actuarial Loss	1.2	1.2
Net Periodic Benefit Cost (Credit)	2.3	2.3
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.8	2.6
Interest Cost	14.8	15.2
Expected Return on Plan Assets	(25.3)	(26.8)
Amortization of Prior Service Cost (Credit)	(17.3)	(17.3)
Amortization of Net Actuarial Loss	9.2	7.9
Net Periodic Benefit Cost (Credit)	(15.8)	(18.4)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.2
Interest Cost	2.6	2.7
Expected Return on Plan Assets	(4.1)	(4.3)
Amortization of Prior Service Cost (Credit)	(2.5)	(2.5)
Amortization of Net Actuarial Loss	1.6	1.4
Net Periodic Benefit Cost (Credit)	(2.1)	(2.5)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.4	0.4
Interest Cost	1.7	1.8
Expected Return on Plan Assets	(3.1)	(3.2)
Amortization of Prior Service Cost (Credit)	(2.3)	(2.4)
Amortization of Net Actuarial Loss	1.1	0.9
Net Periodic Benefit Cost (Credit)	(2.2)	(2.5)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	1.7	1.7
Expected Return on Plan Assets	(3)	(3.2)
Amortization of Prior Service Cost (Credit)	(1.7)	(1.7)
Amortization of Net Actuarial Loss	1.1	0.9
Net Periodic Benefit Cost (Credit)	(1.7)	(2.1)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	0.8	0.8
Expected Return on Plan Assets	(1.4)	(1.5)
Amortization of Prior Service Cost (Credit)	(1.1)	(1.1)
Amortization of Net Actuarial Loss	0.5	0.4
Net Periodic Benefit Cost (Credit)	(1)	(1.2)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2
Interest Cost	0.9	0.9
Expected Return on Plan Assets	(1.6)	(1.7)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.3)
Amortization of Net Actuarial Loss	0.6	0.5
Net Periodic Benefit Cost (Credit)	$ (1.2)	$ (1.4)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Reportable Segment Information
Sales Revenue, Net		$ 3,933.3	$ 4,044.9
Revenues		3,933.3	4,044.9
NET INCOME (LOSS)		594.2	503.1
Balance Sheet Information
Total Property, Plant and Equipment		62,910.5		$ 62,036.6
Accumulated Depreciation and Amortization		16,674.2		16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		46,236.3		45,639.3
Assets Held for Sale		9.7		1,951.2
Total Assets		61,728.3		63,467.7
Long-term Debt Due Within One Year		2,514.2		2,878
Long-term Debt - Affiliated		0		0
Long-term Debt		16,722.2		17,378.4
Total Long-term Debt Outstanding		19,236.4		20,256.4
Liabilities Held for Sale		3.5		235.9
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		2,269.8	2,218.1
Revenues		2,290.4	2,245.6
NET INCOME (LOSS)		220.5	278.7
Balance Sheet Information
Total Property, Plant and Equipment		41,780.5		41,552.6
Accumulated Depreciation and Amortization		12,712.9		12,596.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		29,067.6		28,955.9
Assets Held for Sale		0		0
Total Assets		37,562.2		37,428.3
Long-term Debt Due Within One Year		1,518.9		1,519.9
Long-term Debt - Affiliated		40		20
Long-term Debt		9,938.9		10,353.3
Total Long-term Debt Outstanding		11,497.8		11,893.2
Liabilities Held for Sale		0		0
Transmission And Distribution Companies [Member]
Reportable Segment Information
Sales Revenue, Net		1,066.4	1,077.3
Revenues		1,086.4	1,096.8
NET INCOME (LOSS)		119.1	107.5
Balance Sheet Information
Total Property, Plant and Equipment		14,990.4		14,762.2
Accumulated Depreciation and Amortization		3,697.8		3,655
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		11,292.6		11,107.2
Assets Held for Sale		0		0
Total Assets		14,813.5		14,802.4
Long-term Debt Due Within One Year		316.4		309.4
Long-term Debt - Affiliated		0		0
Long-term Debt		4,554.4		4,672.2
Total Long-term Debt Outstanding		4,870.8		4,981.6
Liabilities Held for Sale		0		0
AEP Transmission Holdco [Member]
Reportable Segment Information
Sales Revenue, Net		27.7	29.3
Revenues		156.1	88.6
NET INCOME (LOSS)		72.8	44.7
Balance Sheet Information
Total Property, Plant and Equipment		5,665.4		5,354
Accumulated Depreciation and Amortization		120.7		101.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,544.7		5,252.6
Assets Held for Sale		0		0
Total Assets		6,721.4		6,384.8
Long-term Debt Due Within One Year		130.7		0
Long-term Debt - Affiliated		0		0
Long-term Debt		1,931.4		2,055.7
Total Long-term Debt Outstanding		2,062.1		2,055.7
Liabilities Held for Sale		0		0
Generation And Marketing [Member]
Reportable Segment Information
Sales Revenue, Net		558.8	713.9
Revenues		591.4	748
NET INCOME (LOSS)		186.2	70.7
Balance Sheet Information
Total Property, Plant and Equipment		483.7		364.7
Accumulated Depreciation and Amortization		140.4		42.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		343.3		322.5
Assets Held for Sale		9.7		1,951.2
Total Assets		2,194.9		3,386.1
Long-term Debt Due Within One Year		0.1		500.1
Long-term Debt - Affiliated		32.2		32.2
Long-term Debt		0		0
Total Long-term Debt Outstanding		32.3		532.3
Liabilities Held for Sale		3.5		235.9
All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[1]	10.6	6.3
Revenues	[1]	26.5	24.4
NET INCOME (LOSS)	[1]	(4.4)	1.5
Balance Sheet Information
Total Property, Plant and Equipment	[1]	357.2		356.6
Accumulated Depreciation and Amortization	[1]	188.7		186
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	168.5		170.6
Assets Held for Sale	[1]	0		0
Total Assets	[1]	21,233.1		20,354.8
Long-term Debt Due Within One Year	[1]	548.1		548.6
Long-term Debt - Affiliated	[1]	0		0
Long-term Debt	[1]	297.5		297.2
Total Long-term Debt Outstanding	[1]	845.6		845.8
Liabilities Held for Sale	[1]	0		0
Consolidation, Eliminations [Member]
Reportable Segment Information
Sales Revenue, Net		0	0
Revenues		(217.5)	(158.5)
NET INCOME (LOSS)		0	0
Balance Sheet Information
Total Property, Plant and Equipment	[2]	(366.7)		(353.5)
Accumulated Depreciation and Amortization	[2]	(186.3)		(184)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[2]	(180.4)		(169.5)
Assets Held for Sale		0		0
Total Assets	[2],[3]	(20,796.8)		(18,888.7)
Long-term Debt Due Within One Year		0		0
Long-term Debt - Affiliated		(72.2)		(52.2)
Long-term Debt		0		0
Total Long-term Debt Outstanding		(72.2)		(52.2)
Liabilities Held for Sale		0		$ 0
Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		0	0
Segment Reconciling Items [Member] | Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		20.6	27.5
Segment Reconciling Items [Member] | Transmission And Distribution Companies [Member]
Reportable Segment Information
Sales Revenue, Net		20	19.5
Segment Reconciling Items [Member] | AEP Transmission Holdco [Member]
Reportable Segment Information
Sales Revenue, Net		128.4	59.3
Segment Reconciling Items [Member] | Generation And Marketing [Member]
Reportable Segment Information
Sales Revenue, Net		32.6	34.1
Segment Reconciling Items [Member] | All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[1]	15.9	18.1
Segment Reconciling Items [Member] | Consolidation, Eliminations [Member]
Reportable Segment Information
Sales Revenue, Net		$ (217.5)	$ (158.5)
[1]	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
[2]	Includes eliminations due to an intercompany capital lease.
[3]	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions		3 Months Ended			12 Months Ended
		Mar. 31, 2017USD ($)MWhMMBTUTgal		Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)MWhMMBTUTgal
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 5.5			$ 7.9
Cash Collateral Paid Netted Against Risk Management Liabilities		21.9			7.6
Fair Value of Derivative Instruments
Current Risk Management Assets		85			94.5
Long-term Risk Management Assets		310.5			289.1
Total Assets		395.5			383.6
Current Risk Management Liabilities		68.2			53.4
Long-term Risk Management Liabilities		344.8			316.2
Derivative Liability		413			369.6
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		29.1		$ 19.1
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments		(0.5)		3.5
Gain (Loss) on Fair Value Portion of Long-term Debt		0.5		(3.5)
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		35.2			9.3
Amount Attributable to Other Contracts	[1]	197.2			280.3
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		287.1			259.6
Amount of Cash Collateral Posted		6.5			0.4
Additional Settlement Liability if Cross Default Provision is Triggered		$ 267.4			235.8
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows		129 months
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 0			0.5
Cash Collateral Paid Netted Against Risk Management Liabilities		0.3			0.7
Fair Value of Derivative Instruments
Current Risk Management Assets		1.1			2.6
Long-term Risk Management Assets		0.2			0
Current Risk Management Liabilities		6.6			0.3
Long-term Risk Management Liabilities		0.1			0.9
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6.3		17.5
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		6.7			1
Amount Attributable to Other Contracts		0			0
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0.1
Amount of Cash Collateral Posted		0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0
Indiana Michigan Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0.3
Cash Collateral Paid Netted Against Risk Management Liabilities		0.2			0.4
Fair Value of Derivative Instruments
Current Risk Management Assets		2.4			3.5
Long-term Risk Management Assets		0.6			0
Current Risk Management Liabilities		2.8			0.3
Long-term Risk Management Liabilities		0.1			0.8
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		11.9		9.7
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		3.9			0.6
Amount Attributable to Other Contracts		0			0
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0.1
Amount of Cash Collateral Posted		0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0
Ohio Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0.2
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0
Fair Value of Derivative Instruments
Current Risk Management Assets		0.1			0.2
Current Risk Management Liabilities		6.3			5.9
Long-term Risk Management Liabilities		118.3			113.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(8.6)		(30.3)
Public Service Co Of Oklahoma [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0.1
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0
Fair Value of Derivative Instruments
Current Risk Management Assets		0.5			0.8
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2.4		(0.7)
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		5.1			2.1
Amount Attributable to Other Contracts		3.2			3.2
Southwestern Electric Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0.1
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0
Fair Value of Derivative Instruments
Current Risk Management Assets		0.6			0.9
Current Risk Management Liabilities		0.4			0.3
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		4.5		4.4
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		6.1			2.5
Amount Attributable to Other Contracts		0.1			0.1
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[2]	382.5	[3]		372.4	[4]
Derivative Liability	[2]	337.5	[3]		321.5	[4]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	1.3			2.6
Derivative Liability	[2],[5]	6.7			1.2
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	3			3.5
Derivative Liability	[2],[5]	2.9			1.1
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets		0.1			0.2	[2],[5]
Derivative Liability	[2],[5]	124.6			119
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.5			0.8
Derivative Liability	[2],[5]	0
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.6			0.9
Derivative Liability	[2],[5]	0.4			0.3
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[6]	13			11.2
Hedging Liabilities	[6]	73.6			46.7
AOCI Gain (Loss) Net of Tax		(39.6)			(23.1)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		3.3			4.3
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50			50
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	245.8			264.4
Long-term Risk Management Assets	[7]	361.7			315
Total Assets	[7]	607.5			579.4
Current Risk Management Liabilities	[7]	232.9			227.2
Long-term Risk Management Liabilities	[7]	346			301
Derivative Liability	[7]	578.9			528.2
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	28.6			51.2
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	19.2			22.7
Long-term Risk Management Assets	[8]	5.7			1.9
Total Assets	[8]	24.9			24.6
Current Risk Management Liabilities	[8]	24.7			20.6
Long-term Risk Management Liabilities	[8]	5.9			2.8
Derivative Liability	[8]	30.6			23.4
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(5.7)			1.2
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	16.7			14.9
Long-term Risk Management Assets	[8]	3.9			1.1
Total Assets	[8]	20.6			16
Current Risk Management Liabilities	[8]	17.1			11.8
Long-term Risk Management Liabilities	[8]	3.6			1.9
Derivative Liability	[8]	20.7			13.7
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(0.1)			2.3
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.1			0.4
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	0.1			0.4
Current Risk Management Liabilities	[8]	6.3			5.9
Long-term Risk Management Liabilities	[8]	118.3			113.1
Derivative Liability	[8]	124.6			119
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(124.5)			(118.6)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.5			0.9
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	0.5			0.9
Current Risk Management Liabilities	[8]	0			0
Long-term Risk Management Liabilities	[8]	0			0
Derivative Liability	[8]	0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0.5			0.9
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.6			1.1
Long-term Risk Management Assets	[8]	0			0
Total Assets	[8]	0.6			1.1
Current Risk Management Liabilities	[8]	0.4			0.4
Long-term Risk Management Liabilities	[8]	0			0
Derivative Liability	[8]	0.4			0.4
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0.2			0.7
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	16.2			13.2
Long-term Risk Management Assets	[7]	4.9			7.7
Total Assets	[7]	21.1			20.9
Current Risk Management Liabilities	[7]	10.8			6.3
Long-term Risk Management Liabilities	[7]	70.9			50.1
Derivative Liability	[7]	81.7			56.4
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(60.6)			(35.5)
Interest Rate and Foreign Currency [Member]
Commodity:
Derivative, Notional Amount		500			500
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[6]	0			0
Hedging Liabilities	[6]	0			0
AOCI Gain (Loss) Net of Tax		(15.3)			(15.7)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1)			(1)
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		2.7			2.9
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0.7			0.7
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(11.7)			(12)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1.3)			(1.3)
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		2.8			3
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		1.1			1.1
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		3.2			3.4
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0.8			0.8
Interest Rate and Foreign Currency [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(6.9)			(7.4)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1.4)			(1.4)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0			0
Long-term Risk Management Assets	[7]	0			0
Total Assets	[7]	0			0
Current Risk Management Liabilities	[7]	0			0
Long-term Risk Management Liabilities	[7]	1.9			1.4
Derivative Liability	[7]	1.9			1.4
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(1.9)			(1.4)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		262			277.6
Long-term Risk Management Assets		366.6			322.7
Total Assets		628.6			600.3
Current Risk Management Liabilities		243.7			233.5
Long-term Risk Management Liabilities		418.8			352.5
Derivative Liability		662.5			586
Total MTM Derivative Contract Net Assets (Liabilities)		(33.9)			14.3
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(177)			(183.1)
Long-term Risk Management Assets	[9]	(56.1)			(33.6)
Total Assets	[9]	(233.1)			(216.7)
Current Risk Management Liabilities	[9]	(175.5)			(180.1)
Long-term Risk Management Liabilities	[9]	(74)			(36.3)
Derivative Liability	[9]	(249.5)			(216.4)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	16.4			(0.3)
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	(18.1)			(20.1)
Long-term Risk Management Assets	[10]	(5.5)			(1.9)
Total Assets	[10]	(23.6)			(22)
Current Risk Management Liabilities	[10]	(18.1)			(20.3)
Long-term Risk Management Liabilities	[10]	(5.8)			(1.9)
Derivative Liability	[10]	(23.9)			(22.2)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.3			0.2
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	(14.3)			(11.4)
Long-term Risk Management Assets	[10]	(3.3)			(1.1)
Total Assets	[10]	(17.6)			(12.5)
Current Risk Management Liabilities	[10]	(14.3)			(11.5)
Long-term Risk Management Liabilities	[10]	(3.5)			(1.1)
Derivative Liability	[10]	(17.8)			(12.6)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.2			0.1
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			(0.2)
Long-term Risk Management Assets	[10]	0			0
Total Assets	[10]	0			(0.2)
Current Risk Management Liabilities	[10]	0			0
Long-term Risk Management Liabilities	[10]	0			0
Derivative Liability	[10]	0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			(0.2)
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	[10]	0			(0.1)
Long-term Risk Management Assets	[10]	0			0
Total Assets	[10]	0			(0.1)
Current Risk Management Liabilities	[10]	0			0
Long-term Risk Management Liabilities	[10]	0			0
Derivative Liability	[10]	0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			(0.1)
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			(0.2)
Long-term Risk Management Assets	[10]	0			0
Total Assets	[10]	0			(0.2)
Current Risk Management Liabilities	[10]	0			(0.1)
Long-term Risk Management Liabilities	[10]	0			0
Derivative Liability	[10]	0			(0.1)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			(0.1)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	85			94.5
Long-term Risk Management Assets	[11]	310.5			289.1
Total Assets	[11]	395.5			383.6
Current Risk Management Liabilities	[11]	68.2			53.4
Long-term Risk Management Liabilities	[11]	344.8			316.2
Derivative Liability	[11]	413			369.6
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	(17.5)			14
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]	1.1			2.6
Long-term Risk Management Assets	[12]	0.2			0
Total Assets	[12]	1.3			2.6
Current Risk Management Liabilities	[12]	6.6			0.3
Long-term Risk Management Liabilities	[12]	0.1			0.9
Derivative Liability	[12]	6.7			1.2
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	(5.4)			1.4
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]	2.4			3.5
Long-term Risk Management Assets	[12]	0.6			0
Total Assets	[12]	3			3.5
Current Risk Management Liabilities	[12]	2.8			0.3
Long-term Risk Management Liabilities	[12]	0.1			0.8
Derivative Liability	[12]	2.9			1.1
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	0.1			2.4
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]	0.1			0.2
Long-term Risk Management Assets	[12]	0			0
Total Assets	[12]	0.1			0.2
Current Risk Management Liabilities	[12]	6.3			5.9
Long-term Risk Management Liabilities	[12]	118.3			113.1
Derivative Liability	[12]	124.6			119
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	(124.5)			(118.8)
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]	0.5			0.8
Long-term Risk Management Assets	[12]	0			0
Total Assets	[12]	0.5			0.8
Current Risk Management Liabilities	[12]	0			0
Long-term Risk Management Liabilities	[12]	0			0
Derivative Liability	[12]	0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	0.5			0.8
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]	0.6			0.9
Long-term Risk Management Assets	[12]	0			0
Total Assets	[12]	0.6			0.9
Current Risk Management Liabilities	[12]	0.4			0.3
Long-term Risk Management Liabilities	[12]	0			0
Derivative Liability	[12]	0.4			0.3
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	$ 0.2			$ 0.6
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		301			348
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		33.1			51.9
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		18.9			19.9
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		10.9			11.2
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		4.6			11.9
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		5.5			14.2
Coal [Member]
Commodity:
Derivative, Mass Notional Amount | T		1.4			1.5
Coal [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.7			0.5
Coal [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.7			1
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		24.3			32.8
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			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		0			0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		5.4			7.4
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1			1.4
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.5			0.7
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.2			1.6
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.6			0.8
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.6			0.9
Interest Rate Contract [Member]
Commodity:
Derivative, Notional Amount		$ 70.3			$ 75.2
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0.1
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0.1
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		5.5		0.6
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
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
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
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
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
Transmission and Distribution Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				(3.5)
Transmission and Distribution Utilities Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Transmission and Distribution Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Transmission and Distribution Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Transmission and Distribution Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Transmission and Distribution Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Generation & Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		10.5		19.8
Generation & 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
Generation & 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
Generation & 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
Generation & 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
Generation & 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
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
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		0.4		(0.8)
Electric Generation, Transmission and Distribution Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		5.2		1.6
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		(3.5)
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
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		0.1		0
Sales to AEP Affiliates [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Sales to AEP Affiliates [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				1.1
Sales to AEP Affiliates [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				4
Sales to AEP Affiliates [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Sales to AEP Affiliates [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2.4		2.1
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		0.8		1.4
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.1		0.1
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
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
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
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.2		(0.7)
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		0		(0.1)
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		0		(0.1)
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		0		(0.1)
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		0		(0.1)
Other Operation Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.2		(0.8)
Maintenance Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.2)
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		0		(0.1)
Maintenance Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)
Maintenance Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(14.9)		(11.1)
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]	(5.8)		0.2
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]	(0.2)		0.3
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]	(8.6)		(11.4)
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]	0		(0.5)
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]	(0.2)		0.1
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	25.2		12.7
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]	10.9		15.9
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]	6.8		3.9
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]	0		(15.2)
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]	2.4		0
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]	$ 4.6		$ 4.5
[1]	Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
[2]	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.’’
[3]	The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[4]	The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[5]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[6]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
[7]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[9]	Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[10]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[11]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[12]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not 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		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 19,236.4		$ 20,256.4
Long Term Debt, Fair Value		21,239.5
Other Temporary Investments
Cost		260.3		318.8
Gross Unrealized Gains		15.5		13.9
Gross Unrealized Losses		(0.8)		(1)
Fair Value		275		331.7
Debt and Equity Securities Within Other Temporary Investments
Proceeds from Investment Sales		0	$ 0
Purchases of Investments		0.5	0.4
Gross Realized Gains on Investment Sales		0	0
Gross Realized Losses on Investment Sales		0	0
Nuclear Trust Fund Investments
Fair Value		2,333.2		2,256.2
Gross Unrealized Gains		771.7		707.7
Other-Than-Temporary Impairments		(85.7)		(87.2)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		487.9	1,137.7
Purchases of Investments		505.5	1,151.6
Gross Realized Gains on Investment Sales		11.3	15.8
Gross Realized Losses on Investment Sales		8.1	7.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,333.2		2,256.2
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		21,239.5
Adjusted Cost of Debt Securities		942		938
Adjusted Cost of Domestic Equity Securities		603		592
Includes Debt Included In Liabilities Held For Sale [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding	[1]			20,391.2
Long Term Debt, Fair Value	[1]			22,211.9
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value	[1]			22,211.9
Lawrenceburg Plant [Member]
Book Values and Fair Values of Long - term Debt
Long Term Debt, Fair Value				172
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value				172
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,918.8		4,033.9
Long Term Debt, Fair Value		4,558.8		4,613.2
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		4,558.8		4,613.2
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,439.5		2,471.4
Long Term Debt, Fair Value		2,646.8		2,661.6
Nuclear Trust Fund Investments
Fair Value		2,333.2		2,256.2
Gross Unrealized Gains		771.7		707.7
Other-Than-Temporary Impairments		(85.7)		(87.2)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		487.9	1,137.7
Purchases of Investments		505.5	1,151.6
Gross Realized Gains on Investment Sales		11.3	15.8
Gross Realized Losses on Investment Sales		8.1	$ 7.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,333.2		2,256.2
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,646.8		2,661.6
Adjusted Cost of Debt Securities		942		938
Adjusted Cost of Domestic Equity Securities		603		592
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,742		1,763.9
Long Term Debt, Fair Value		2,070.8		2,092.5
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,070.8		2,092.5
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,286.1		1,286
Long Term Debt, Fair Value		1,431.1		1,419
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		1,431.1		1,419
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,427.7		2,679.1
Long Term Debt, Fair Value		2,591.2		2,814.3
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,591.2		2,814.3
Cash [Member]
Other Temporary Investments
Cost	[2]	152.7		211.7
Gross Unrealized Gains	[2]	0		0
Gross Unrealized Losses	[2]	0		0
Fair Value	[2],[3]	152.7		211.7
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		973.3		967.4
Gross Unrealized Gains		31.1		29.8
Other-Than-Temporary Impairments		(6.8)		(7.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		973.3		967.4
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		973.3		967.4
Gross Unrealized Gains		31.1		29.8
Other-Than-Temporary Impairments		(6.8)		(7.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		973.3		967.4
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[4]	93.1		92.7
Gross Unrealized Gains	[4]	0		0
Gross Unrealized Losses	[4]	(0.8)		(1)
Fair Value	[4]	92.3		91.7
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,343.3		1,270.1
Gross Unrealized Gains		740.6		677.9
Other-Than-Temporary Impairments		(78.9)		(79.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[5]	1,343.3		1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,343.3		1,270.1
Gross Unrealized Gains		740.6		677.9
Other-Than-Temporary Impairments		(78.9)		(79.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[5]	1,343.3		1,270.1
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		14.5		14.4
Gross Unrealized Gains		15.5		13.9
Gross Unrealized Losses		0		0
Fair Value	[5]	30		28.3
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	16.6		18.7
Gross Unrealized Gains		0		0
Other-Than-Temporary Impairments		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	16.6		18.7
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	16.6		18.7
Gross Unrealized Gains		0		0
Other-Than-Temporary Impairments		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	16.6		18.7
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		814.2		785.4
Gross Unrealized Gains		28.4		27.1
Other-Than-Temporary Impairments		(4.6)		(5.5)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		814.2		785.4
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		814.2		785.4
Gross Unrealized Gains		28.4		27.1
Other-Than-Temporary Impairments		(4.6)		(5.5)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		814.2		785.4
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		57.2		60.9
Gross Unrealized Gains		2.5		2.3
Other-Than-Temporary Impairments		(1.2)		(1.4)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		57.2		60.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		57.2		60.9
Gross Unrealized Gains		2.5		2.3
Other-Than-Temporary Impairments		(1.2)		(1.4)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		57.2		60.9
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		101.9		121.1
Gross Unrealized Gains		0.2		0.4
Other-Than-Temporary Impairments		(1)		(0.7)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		101.9		121.1
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		101.9		121.1
Gross Unrealized Gains		0.2		0.4
Other-Than-Temporary Impairments		(1)		(0.7)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		101.9		$ 121.1
Within One Year [Member]
Nuclear Trust Fund Investments
Fair Value		221.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		221.8
Within One Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		221.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		221.8
One Year To Five Year [Member]
Nuclear Trust Fund Investments
Fair Value		346.3
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		346.3
One Year To Five Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		346.3
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		346.3
Five Year To Ten Year [Member]
Nuclear Trust Fund Investments
Fair Value		192.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		192.8
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		192.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		192.8
After Ten Year [Member]
Nuclear Trust Fund Investments
Fair Value		212.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		212.4
After Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		212.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		$ 212.4
[1]	Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See the Assets and Liabilities Held for Sale section of Note 6 for additional information.
[2]	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.
[3]	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[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]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Fair Value Assets and Liabiliti

Fair Value Assets and Liabilities (Details) $ in Millions		3 Months Ended				12 Months Ended
		Mar. 31, 2017USD ($)$ / MWh		Mar. 31, 2016USD ($)		Dec. 31, 2016USD ($)$ / MWh
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 175				$ 210.5
Other Temporary Investments		275				331.7
Risk Management Assets
Risk Management Assets		395.5				383.6
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,333.2				2,256.2
Total Assets		3,178.7				3,182
Liabilities, Fair Value Disclosure
Risk Management Liabilities		413				369.6
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		2.5		$ 146.9		146.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	17.8		23.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	16.1		21.9
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		(17.2)		1.3
Settlements		(28.8)		(42.7)
Transfers into Level 3	[4]	5.2
Transfers out of Level 3	[4]	(8.3)		10.9
Changes in Fair Value Allocated to Regulated Jurisdictions	[5]	(5.8)		(20.5)
Ending Balance		$ (18.5)		141.3		$ 2.5
Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[6]	0.17%				0.35%
High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[6]	6.91%				8.24%
Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[6]	2.59%				3.91%
Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 166.1				$ 201.8
Other Temporary Investments		15.2				32.8
Risk Management Assets
Risk Management Assets		(178.7)				(213)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7.7				11.4
Total Assets		10.3				33
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(195.1)				(212.7)
Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	8.9				8.7
Other Temporary Investments		258.5				293.8
Risk Management Assets
Risk Management Assets		1.8				6
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,352.2				1,277.4
Total Assets		1,621.4				1,585.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		5.4				8.2
Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Other Temporary Investments		1.3				5.1
Risk Management Assets
Risk Management Assets		367				396.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		973.3				967.4
Total Assets		1,341.6				1,369.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities		378.8				382.7
Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Other Temporary Investments		0				0
Risk Management Assets
Risk Management Assets		205.4				193.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Total Assets		205.4				193.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		223.9				191.4
2017 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(2)
2017 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		5				20
2017 [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				17
2018 - 2020 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(2)				(2)
2018 - 2020 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		6				4
2018 - 2020 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		24				28
2021 - 2022 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1				3
2021 - 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		14				11
2023 - 2032 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1				1
2023 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(24)				(31)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7]	382.5	[8]			372.4	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	337.5	[8]			321.5	[9]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(176.9)	[8]			(205.7)	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	(193.3)	[8]			(205.4)	[9]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	1.8	[8]			6	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	5.4	[8]			8.2	[9]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	353.3	[8]			379.9	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	340.6	[8]			352	[9]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	204.3	[8]			192.2	[9]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	184.8	[8]			166.7	[9]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		199.5				183.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 213.5				$ 187.1
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	9.65				6.51
Forward Price Range High | $ / MWh	[10]	92.72				86.59
Weighted Average Market Price | $ / MWh	[10]	38.24				39.40
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 5.9				$ 10.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 10.4				$ 4.3
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	(5.46)				(7.99)
Forward Price Range High | $ / MWh	[10]	7.22				8.91
Weighted Average Market Price | $ / MWh	[10]	0.50				0.86
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[7]	$ 13				$ 11.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	73.6				46.7
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(1.8)				(7.3)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	(1.8)				(7.3)
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	0				0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	13.7				16.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	36.3				29.3
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	1.1				1.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7]	39.1				24.7
Fair Value Hedges [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.9				1.4
Fair Value Hedges [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0
Fair Value Hedges [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0
Fair Value Hedges [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.9				1.4
Fair Value Hedges [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	8.1				15.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		9.4				18.5
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		1.4		11.7	[11]	11.7	[11]
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	5.7		15.3	[11]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0	[11]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	[11]
Settlements		(12.2)		(27.7)	[11]
Transfers into Level 3	[4],[11]	0
Transfers out of Level 3	[4]	0		0.1	[11]
Changes in Fair Value Allocated to Regulated Jurisdictions	[5]	(0.7)		3.2	[11]
Ending Balance		(5.8)		2.6	[11]	1.4
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0.1				0.1
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(17.2)				(21.7)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	8				15.8
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		8				15.8
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16.6				20.5
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Risk Management Assets
Risk Management Assets		2				3.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		2				3.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		7.8				2.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	1.3				2.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	6.7				1.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(17.3)				(21.8)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(17.6)				(22)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0				0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	16.6				20.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	16.5				20.7
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	2				3.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	7.8				2.5
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.6				0.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2				$ 0.4
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	19.36				19.68
Forward Price Range High | $ / MWh	[10]	46.45				48.55
Weighted Average Market Price | $ / MWh	[10]	34.61				36.34
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 1.4				$ 3.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 7.6				$ 2.1
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	0.04				(0.23)
Forward Price Range High | $ / MWh	[10]	4.14				8.91
Weighted Average Market Price | $ / MWh	[10]	1.34				2.37
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,333.2				$ 2,256.2
Total Assets		2,336.2				2,259.7
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		2.8		4.3	[11]	4.3	[11]
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	2		2.5	[11]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0	[11]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	[11]
Settlements		(4.3)		(4.6)	[11]
Transfers into Level 3	[4],[11]	0
Transfers out of Level 3	[4]	0		0.1	[11]
Changes in Fair Value Allocated to Regulated Jurisdictions	[5]	1.5		1.4	[11]
Ending Balance		2		3.7	[11]	2.8
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7.7				11.4
Total Assets		(6.1)				(0.9)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,352.2				1,277.4
Total Assets		1,352.2				1,277.4
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		973.3				967.4
Total Assets		987.9				980.2
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2.2				3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Total Assets		2.2				3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.2				0.2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	3				3.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	2.9				1.1
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(13.8)				(12.3)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(14)				(12.4)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0				0
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	14.6				12.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	16.7				13.3
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	2.2				3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.2				0.2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.3				0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0.2
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	19.36				19.68
Forward Price Range High | $ / MWh	[10]	46.45				48.55
Weighted Average Market Price | $ / MWh	[10]	34.61				36.34
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 1.9				$ 2.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	(0.33)				(7.9)
Forward Price Range High | $ / MWh	[10]	3.7				8.91
Weighted Average Market Price | $ / MWh	[10]	1.75				1.32
Ohio Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 16				$ 27.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16.1				27.4
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(119)		15.9		15.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(0.5)		(0.6)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0
Settlements		2.1		1.4
Transfers into Level 3	[4]	0
Transfers out of Level 3	[4]	0		0
Changes in Fair Value Allocated to Regulated Jurisdictions	[5]	(7.2)		(27.6)
Ending Balance		$ (124.6)		(10.9)		$ (119)
Ohio Power Co [Member] | Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[6]	0.34%				0.47%
Ohio Power Co [Member] | High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[6]	3.27%				3.40%
Ohio Power Co [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[6]	2.45%				2.72%
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 0				$ 27.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0				27
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	16				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16				0
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.1				0.4
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Risk Management Assets
Risk Management Assets		0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		124.6				119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets		0.1				0.2	[7],[12]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	124.6				119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0				(0.2)	[7],[12]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0				0	[7],[12]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		0.1				0.4	[7],[12]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0				0	[7],[12]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	124.6				119
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 124.6				$ 119
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	28.17				30.14
Forward Price Range High | $ / MWh	[10]	70.98				71.85
Weighted Average Market Price | $ / MWh	[10]	46.04				47.45
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ 0.7		0.6		$ 0.6
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	2.2		(0.8)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0
Settlements		(2.6)		0.5
Transfers into Level 3	[4]	0
Transfers out of Level 3	[4]	0		0
Changes in Fair Value Allocated to Regulated Jurisdictions	[5]	0.1		0.3
Ending Balance		0.4		0.6		0.7
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.5				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(0.1)				(0.1)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(0.1)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.1				0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.5				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.1
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.5				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	(3.51)				(7.99)
Forward Price Range High | $ / MWh	[10]	3.13				1.03
Weighted Average Market Price | $ / MWh	[10]	(0.40)				(0.36)
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 10.3				$ 10.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		10.9				11.2
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		0.7		0.8		0.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	4.5		4.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0
Settlements		(4.9)		(4.9)
Transfers into Level 3	[4]	0
Transfers out of Level 3	[4]	0		0
Changes in Fair Value Allocated to Regulated Jurisdictions	[5]	0.2		0.2
Ending Balance		0.5		$ 0.7		0.7
Southwestern Electric Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	1.4				1.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		1.3				1.4
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	8.9				8.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		8.9				8.7
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.1				0.3
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.6				0.8
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.6				0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.4				0.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(0.1)				(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	(0.1)				(0.1)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0				0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.1				0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.4				0.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.6				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[7],[12]	0.1				0.1
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.6				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0.1
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[10]	(3.51)				(7.99)
Forward Price Range High | $ / MWh	[10]	3.13				1.03
Weighted Average Market Price | $ / MWh	[10]	(0.40)				(0.36)
Cash [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1],[13]	$ 152.7				$ 211.7
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	15.2				32.8
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	136.2				173.8
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	1.3				5.1
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	0				0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		973.3				967.4
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		973.3				967.4
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		973.3				967.4
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		973.3				967.4
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[14]	92.3				91.7
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		92.3				91.7
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	[15]	30				28.3
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[15]	0				0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[15]	30				28.3
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[15]	0				0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[15]	0				0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	16.6				18.7
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	7.7				11.4
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	8.9				7.3
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0				0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0				0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	16.6				18.7
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	7.7				11.4
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	8.9				7.3
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0				0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0				0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		814.2				785.4
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		814.2				785.4
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		814.2				785.4
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		814.2				785.4
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.2				60.9
Corporate Debt [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.2				60.9
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.2				60.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.2				60.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		101.9				121.1
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		101.9				121.1
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		101.9				121.1
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		101.9				121.1
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,343.3				1,270.1
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0				0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,343.3				1,270.1
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0				0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0				0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,343.3				1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0				0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,343.3				1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0				0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	$ 0				$ 0
[1]	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[2]	Included in revenues on the statements of income.
[3]	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
[4]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[5]	Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
[6]	Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[7]	Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’
[8]	The March 31, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $5 million in 2017, $6 million in periods 2018-2020, $1 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $6 million in 2017, $24 million in periods 2018-2020, $14 million in periods 2021-2022 and $(24) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[9]	The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[10]	Represents market prices in dollars per MWh.
[11]	Includes both affiliated and nonaffiliated transactions.
[12]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[13]	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.
[14]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[15]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[16]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended
		Apr. 27, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Long-term Debt
Senior Unsecured Notes			$ 14,360.2		$ 14,761
Pollution Control Bonds			1,620.8		1,725.1
Notes Payable			293.2		326.9
Securitization Bonds			1,582.1		1,705
Spent Nuclear Fuel Obligation	[1]		266.6		266.3
Other Long-term Debt			1,113.5		1,606.9
Total Long-term Debt Outstanding			19,236.4		20,256.4
Long-term Debt Due Within One Year			2,514.2		2,878
Long-term Debt			16,722.2		17,378.4
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]		84
Retirements and Principal Payments			1,242.3	$ 322.4
Short-term Debt:
Securitized Debt for Receivables	[3]		572		673
Commercial Paper			964		1,040
Total Short-term Debt			$ 1,536		$ 1,713
Securitized Debt for Receivables	[3],[4]		1.00%		0.70%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable			1.00%	0.58%
Net Uncollectible Accounts Receivable Written Off			$ 5.9	$ 5.7
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts			872.6		$ 945
Total Principal Outstanding			572		673
Delinquent Securitized Accounts Receivable			49		42.7
Bad Debt Reserves Related to Securitization of Accounts Receivable			27.5		27.7
Unbilled Receivables Related to Securitization of Accounts Receivable			253.6		322.1
Financing Activities (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			310		311
Repayments of Long-term Debt			1,242.3	322.4
Issuance of Long-term Debt	[2]		84
Reacquired Pollution Controls Bonds Held by Trustees			718
Total Commitment from Bank Conduits to Finance Receivables			750
Transource Missouri [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]		$ 7
Interest Rate (Variable)			Variable
Due Date			2,018
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]		$ 7
Due Date			2,018
Transource Missouri [Member] | Other Long Term Debt [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 131
Due Date		2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 131
Due Date		2,018
AEP Generating Co [Member] | Senior Unsecured Notes [Member]
Debt Instrument, Interest Rate, Stated Percentage			6.33%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 152.7
Due Date			2,037
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 152.7
Due Date			2,037
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,439.5		2,471.4
Long-term Debt Due Within One Year			199.1		209.3
Long-term Debt			2,240.4		2,262.1
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			109.5	28.8
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			134.2		136.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.5	1.9
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			418.2	388.1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			109.5	$ 28.8
Reacquired Pollution Controls Bonds Held by Trustees			$ 40
Maximum Percentage Debt to Capitalization			67.50%
Indiana Michigan Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool			$ 291.9
Maximum Loans to Money Pool			12.5
Average Borrowings from Money Pool			234.9
Average Loans to Money Pool			12.5
Net Loans (Borrowings) to/from Utility Money Pool			274.3
Authorized Short Term Borrowing Limit			$ 500
Maximum and Minimum Interest Rates [Abstract]
Maximum Interest Rate			1.27%	0.83%
Minimum Interest Rate			0.92%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed			1.04%	0.72%
Average Interest Rate For Funds Loaned			1.03%	0.74%
Indiana Michigan Power Co [Member] | Notes Payable [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 1.7
Interest Rate (Variable)			Variable
Due Date			2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 1.7
Due Date			2,017
Indiana Michigan Power Co [Member] | Notes Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 7.5
Interest Rate (Variable)			Variable
Due Date			2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 7.5
Due Date			2,019
Indiana Michigan Power Co [Member] | Notes Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 7.9
Interest Rate (Variable)			Variable
Due Date			2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 7.9
Due Date			2,019
Indiana Michigan Power Co [Member] | Notes Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 8
Interest Rate (Variable)			Variable
Due Date			2,020
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 8
Due Date			2,020
Indiana Michigan Power Co [Member] | Notes Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 7.1
Interest Rate (Variable)			Variable
Due Date			2,021
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 7.1
Due Date			2,021
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Debt Instrument, Interest Rate, Stated Percentage			6.00%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 0.4
Due Date			2,025
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 0.4
Due Date			2,025
Indiana Michigan Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]		$ 25
Interest Rate (Variable)			Variable
Due Date			2,019
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]		$ 25
Due Date			2,019
Indiana Michigan Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]		$ 52
Interest Rate (Variable)			Variable
Due Date			2,021
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]		$ 52
Due Date			2,021
Indiana Michigan Power Co [Member] | Pollution Control Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 52
Interest Rate (Variable)			Variable
Due Date			2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 52
Due Date			2,017
Indiana Michigan Power Co [Member] | Pollution Control Bonds Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 25
Interest Rate (Variable)			Variable
Due Date			2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 25
Due Date			2,017
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,918.8		4,033.9
Long-term Debt Due Within One Year			399		503.1
Long-term Debt			3,519.8		3,530.8
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			115.9	$ 136.5
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			131.4		142
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.4	1.8
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			369.7	384.4
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			115.9	$ 136.5
Reacquired Pollution Controls Bonds Held by Trustees			$ 104
Maximum Percentage Debt to Capitalization			67.50%
Appalachian Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool			$ 231.3
Maximum Loans to Money Pool			24.1
Average Borrowings from Money Pool			177.7
Average Loans to Money Pool			23.9
Net Loans (Borrowings) to/from Utility Money Pool			158.7
Authorized Short Term Borrowing Limit			$ 600
Maximum and Minimum Interest Rates [Abstract]
Maximum Interest Rate			1.27%	0.83%
Minimum Interest Rate			0.92%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed			1.04%	0.73%
Average Interest Rate For Funds Loaned			1.03%	0.73%
Appalachian Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 104.4
Interest Rate (Variable)			Variable
Due Date			2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 104.4
Due Date			2,017
Appalachian Power Co [Member] | Securitization Bonds [Member]
Debt Instrument, Interest Rate, Stated Percentage			2.008%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 11.5
Due Date			2,024
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 11.5
Due Date			2,024
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,742		1,763.9
Long-term Debt Due Within One Year			46.8		46.4
Long-term Debt			1,695.2		1,717.5
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			22.5	$ 22.8
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			367.6		388.3
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			5.7	7.9
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			632.3	646.6
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			22.5	$ 22.8
Reacquired Pollution Controls Bonds Held by Trustees			345
Ohio Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool			84
Maximum Loans to Money Pool			56.2
Average Borrowings from Money Pool			35.4
Average Loans to Money Pool			27.9
Net Loans (Borrowings) to/from Utility Money Pool			18.3
Authorized Short Term Borrowing Limit			$ 400
Maximum and Minimum Interest Rates [Abstract]
Maximum Interest Rate			1.27%	0.83%
Minimum Interest Rate			0.92%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed			1.10%	0.00%
Average Interest Rate For Funds Loaned			0.98%	0.73%
Ohio Power Co [Member] | Securitization Bonds [Member]
Debt Instrument, Interest Rate, Stated Percentage			0.958%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 22.4
Due Date			2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 22.4
Due Date			2,018
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,286.1		1,286
Long-term Debt Due Within One Year			0.5		0.5
Long-term Debt			1,285.6		1,285.5
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			0.1	$ 0.1
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			99.4		110.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.5	1.4
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			286.8	272.1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 0.1	$ 0.1
Maximum Percentage Debt to Capitalization			67.50%
Public Service Co Of Oklahoma [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool			$ 163.7
Maximum Loans to Money Pool			0
Average Borrowings from Money Pool			91.8
Average Loans to Money Pool			0
Net Loans (Borrowings) to/from Utility Money Pool			163.7
Authorized Short Term Borrowing Limit			$ 300
Maximum and Minimum Interest Rates [Abstract]
Maximum Interest Rate			1.27%	0.83%
Minimum Interest Rate			0.92%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed			1.06%	0.00%
Average Interest Rate For Funds Loaned			0.00%	0.72%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Debt Instrument, Interest Rate, Stated Percentage			3.00%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 0.1
Due Date			2,027
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 0.1
Due Date			2,027
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,427.7		2,679.1
Long-term Debt Due Within One Year			485.4		353.7
Long-term Debt			1,942.3		2,325.4
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			251.7	$ 1.6
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			107.8		130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.6	1.5
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			341.2	336.1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 251.7	$ 1.6
Maximum Percentage Debt to Capitalization			67.50%
Southwestern Electric Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool			$ 187.5
Maximum Loans to Money Pool			178.6
Average Borrowings from Money Pool			139.5
Average Loans to Money Pool			169.5
Net Loans (Borrowings) to/from Utility Money Pool			167.9
Authorized Short Term Borrowing Limit			$ 350
Maximum and Minimum Interest Rates [Abstract]
Maximum Interest Rate			1.27%	0.83%
Minimum Interest Rate			0.92%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed			1.06%	0.73%
Average Interest Rate For Funds Loaned			0.98%	0.00%
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Loans to Money Pool			$ 2
Average Loans to Money Pool			2
Net Loans (Borrowings) to/from Utility Money Pool			$ 2
Maximum and Minimum Interest Rates [Abstract]
Maximum Interest Rate			1.27%
Minimum Interest Rate			0.92%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Loaned			1.03%
Southwestern Electric Power Co [Member] | Notes Payable [Member]
Debt Instrument, Interest Rate, Stated Percentage			4.58%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 1.6
Due Date			2,032
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 1.6
Due Date			2,032
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member]
Debt Instrument, Interest Rate, Stated Percentage			3.50%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 0.1
Due Date			2,023
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 0.1
Due Date			2,023
Southwestern Electric Power Co [Member] | Senior Unsecured Notes [Member]
Debt Instrument, Interest Rate, Stated Percentage			5.55%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 250
Due Date			2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 250
Due Date			2,017
AEP Texas Central Co [Member] | Securitization Bonds [Member]
Debt Instrument, Interest Rate, Stated Percentage			5.17%
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 89.9
Due Date			2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 89.9
Due Date			2,018
Transource Energy [Member] | Other Long Term Debt [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]	$ 132
Due Date		2,020
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]	$ 132
Due Date		2,020
AEP Generation Resources [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments			$ 500
Interest Rate (Variable)			Variable
Due Date			2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 500
Due Date			2,017
Includes Debt Included In Liabilities Held For Sale [Member]
Long-term Debt
Total Long-term Debt Outstanding	[5]				20,391.2
Long-term Debt Due Within One Year					3,013.4
Long-term Debt					$ 17,377.8
Commercial Paper [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		1.27%		1.02%
[1]	Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $310 million and $311 million as of March 31, 2017 and December 31, 2016, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
[2]	Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
[3]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[4]	Weighted average rate.
[5]	Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See the Assets and Liabilities Held for Sale section of Note 6 for additional information.