Appalachian Power 10-Q 27 Oct 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 26, 2017
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		491,883,887
AEP Transmission Co [Member]
Entity Registrant Name	AEP Transmission Company, LLC
Entity Central Index Key	1,702,494
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Appalachian Power Co [Member]
Entity Registrant Name	APPALACHIAN POWER CO
Entity Central Index Key	6,879
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		13,499,500
Indiana Michigan Power Co [Member]
Entity Registrant Name	INDIANA MICHIGAN POWER CO
Entity Central Index Key	50,172
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,400,000
Ohio Power Co [Member]
Entity Registrant Name	OHIO POWER CO
Entity Central Index Key	73,986
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		27,952,473
Public Service Co Of Oklahoma [Member]
Entity Registrant Name	PUBLIC SERVICE CO OF OKLAHOMA
Entity Central Index Key	81,027
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		9,013,000
Southwestern Electric Power Co [Member]
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER CO
Entity Central Index Key	92,487
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		7,536,640

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues
Vertically Integrated Utilities	$ 2,453.8	$ 2,538.3	$ 6,819.3	$ 6,864.6
Transmission and Distribution Utilities	1,149.7	1,245.4	3,242.7	3,398.9
Generation & Marketing	441.5	823.3	1,386.8	2,192.5
Sales to AEP Affiliates	0	0	0	0
Other Revenues	59.7	45.2	165.7	134
TOTAL REVENUES	4,104.7	4,652.2	11,614.5	12,590
Expenses
Fuel and Other Consumables Used for Electric Generation	707.4	880.1	1,865.3	2,236.1
Purchased Electricity for Resale	718.1	774	2,156.9	2,134.6
Other Operation	636.1	771.1	1,842.5	2,150.7
Maintenance	268	286.3	859.4	854.4
Asset Impairments and Other Related Charges	(2.5)	2,264.9	10.6	2,264.9
Gain on Sale of Merchant Generation Assets	0	0	(226.4)	0
Depreciation and Amortization	518.5	539.3	1,485.9	1,550.2
Taxes Other Than Income Taxes	272.6	264.4	792	767.9
TOTAL EXPENSES	3,118.2	5,780.1	8,786.2	11,958.8
OPERATING INCOME (LOSS)	986.5	(1,127.9)	2,828.3	631.2
Other Income (Expense):
Interest and Investment Income	2.4	2	12.7	6.5
Carrying Costs Income	2.6	1.7	14.2	11.9
Allowance for Equity Funds Used During Construction	20	25.6	62.2	86.1
Gain on Sale of Equity Investment	12.4	0	12.4	0
Interest Expense	(223.3)	(225.3)	(668)	(667.2)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	800.6	(1,323.9)	2,261.8	68.5
Income Tax Expense (Credit)	264	(534.5)	797.8	(134)
Equity Earnings (Loss) of Unconsolidated Subsidiaries	20.1	25.2	63.1	42.8
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	556.7	(764.2)	1,527.1	245.3
Income (Loss) from Discontinued Operations, Net of Tax	0	0	0	(2.5)
Net Income (Loss)	556.7	(764.2)	1,527.1	242.8
Net Income Attributable to Noncontrolling Interests	12	1.6	15.2	5.3
Earnings Attributable to Common Shareholders	$ 544.7	$ (765.8)	$ 1,511.9	$ 237.5
Earnings Per Share
Weighted Average Number of Basic AEP Common Shares Outstanding	491,840,722	491,697,809	491,781,643	491,422,921
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 1.11	$ (1.56)	$ 3.07	$ 0.49
Basic Earnings Per Share Attributable to AEP Common Shareholders from Discontinued Operations	0	0	0	(0.01)
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$ 1.11	$ (1.56)	$ 3.07	$ 0.48
Weighted Average Number of Diluted AEP Common Shares Outstanding	492,986,307	491,813,858	492,428,586	491,596,861
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 1.10	$ (1.56)	$ 3.07	$ 0.49
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Discontinued Operations	0	0	0	(0.01)
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	1.10	(1.56)	3.07	0.48
Common Stock, Dividends Per Share, Declared	$ 0.59	$ 0.56	$ 1.77	$ 1.68
AEP Transmission Co [Member]
Revenues
Electrical Transmission Revenue	$ 35.9	$ 33.5	$ 99.2	$ 89.6
Sales to AEP Affiliates	131.4	91.8	450.2	268.4
TOTAL REVENUES	167.3	125.3	549.4	358
Expenses
Other Operation	18.4	7.5	38.8	21
Maintenance	1.4	1.9	6.8	4.8
Depreciation and Amortization	24.8	16.8	70.9	47.5
Taxes Other Than Income Taxes	27.6	22.7	82	65.4
TOTAL EXPENSES	72.2	48.9	198.5	138.7
OPERATING INCOME (LOSS)	95.1	76.4	350.9	219.3
Other Income (Expense):
Interest Income	0.2	0.1	0.5	0.2
Allowance for Equity Funds Used During Construction	11.7	13.3	36	39.7
Interest Expense	(16.9)	(11)	(48.6)	(32.3)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	90.1	78.8	338.8	226.9
Income Tax Expense (Credit)	30.2	26.4	114.5	73.9
Net Income (Loss)	59.9	52.4	224.3	153
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	674.4	739	2,045	2,153.3
Sales to AEP Affiliates	41.9	36.4	130.6	109
Other Revenues	3	2.8	11.8	9.4
TOTAL REVENUES	719.3	778.2	2,187.4	2,271.7
Expenses
Fuel and Other Consumables Used for Electric Generation	178.6	190.1	498.3	494.1
Purchased Electricity for Resale	61.1	69.2	217.1	240.9
Other Operation	115.7	117.6	366.2	349.4
Maintenance	55.8	66.8	187.8	196.3
Depreciation and Amortization	102.8	98.1	304.1	290
Taxes Other Than Income Taxes	32.3	32	93.3	93.9
TOTAL EXPENSES	546.3	573.8	1,666.8	1,664.6
OPERATING INCOME (LOSS)	173	204.4	520.6	607.1
Other Income (Expense):
Interest Income	0.3	0.3	1.1	0.8
Carrying Costs Income	0.4	0	1	0.2
Allowance for Equity Funds Used During Construction	2.7	4.5	6.2	9.1
Interest Expense	(47.2)	(46.4)	(143.5)	(140.7)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	129.2	162.8	385.4	476.5
Income Tax Expense (Credit)	43.2	58.7	136.7	172.7
Net Income (Loss)	86	104.1	248.7	303.8
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	537	574.7	1,527.4	1,570.8
Other Revenues - Affiliated	17.1	19.5	48.2	68.7
Other Revenues	3.6	3.4	9.9	13.2
TOTAL REVENUES	557.7	597.6	1,585.5	1,652.7
Expenses
Fuel and Other Consumables Used for Electric Generation	76.4	91.3	238.2	236.8
Purchased Electricity for Resale	32.9	43.7	101.2	134.3
Purchased Electricity from AEP Affiliates	62.4	64.5	166.2	165.9
Other Operation	140.5	138.9	434.2	413.9
Maintenance	51.5	45.7	153.6	134.6
Asset Impairments and Other Related Charges	0	10.5	0	10.5
Depreciation and Amortization	55	49.1	154.8	143.2
Taxes Other Than Income Taxes	23.9	22.5	68.3	71.5
TOTAL EXPENSES	442.6	466.2	1,316.5	1,310.7
OPERATING INCOME (LOSS)	115.1	131.4	269	342
Other Income (Expense):
Interest Income	2.4	1.7	11.5	9.1
Allowance for Equity Funds Used During Construction	3.5	4.1	8.1	10.9
Interest Expense	(27.5)	(26.7)	(83)	(76.3)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	93.5	110.5	205.6	285.7
Income Tax Expense (Credit)	28.6	35.1	61.8	84.3
Net Income (Loss)	64.9	75.4	143.8	201.4
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	736	864.4	2,127.8	2,349.2
Sales to AEP Affiliates	4.6	5.5	19.4	11.7
Other Revenues	1.4	1.4	4.8	4.8
TOTAL REVENUES	742	871.3	2,152	2,365.7
Expenses
Purchased Electricity for Resale	180.7	203.4	525.4	516.1
Purchased Electricity from AEP Affiliates	26.7	35.9	83.4	121.4
Amortization of Generation Deferrals	58.7	66.1	172.9	173
Other Operation	125.8	184.2	377.6	525.9
Maintenance	37.9	38.8	108.4	104.4
Depreciation and Amortization	57.3	69.4	165.7	189
Taxes Other Than Income Taxes	100.4	101.9	293.8	291.7
TOTAL EXPENSES	587.5	699.7	1,727.2	1,921.5
OPERATING INCOME (LOSS)	154.5	171.6	424.8	444.2
Other Income (Expense):
Interest Income	0.7	0.7	4	3
Carrying Costs Income	0.5	0.9	3	4
Allowance for Equity Funds Used During Construction	0.9	0.3	4.1	3.7
Interest Expense	(25.7)	(27.2)	(76.8)	(87.7)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	130.9	146.3	359.1	367.2
Income Tax Expense (Credit)	48.3	46.4	128	122.5
Net Income (Loss)	82.6	99.9	231.1	244.7
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	440.6	400.9	1,085.1	971.3
Sales to AEP Affiliates	1.1	0.1	3.2	2
Other Revenues	1.1	0.7	3.3	2.9
TOTAL REVENUES	442.8	401.7	1,091.6	976.2
Expenses
Fuel and Other Consumables Used for Electric Generation	77.9	16.4	115.8	43
Purchased Electricity for Resale	127.8	130.8	379.8	315.3
Purchased Electricity from AEP Affiliates	0	3.2	0	3.6
Other Operation	83.6	81	226.3	211.8
Maintenance	25.2	25.6	88.2	71.6
Depreciation and Amortization	31.7	37.2	97.8	109.9
Taxes Other Than Income Taxes	9.8	9.1	30	27.8
TOTAL EXPENSES	356	303.3	937.9	783
OPERATING INCOME (LOSS)	86.8	98.4	153.7	193.2
Other Income (Expense):
Interest Income	0	0.2	0.1	0.5
Allowance for Equity Funds Used During Construction	0	1.1	0.4	4.9
Interest Expense	(13.2)	(14.9)	(40.2)	(44.6)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	73.6	84.8	114	154
Income Tax Expense (Credit)	27.4	32	42.6	56.6
Net Income (Loss)	46.2	52.8	71.4	97.4
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	509.5	530.5	1,321.8	1,324.1
Sales to AEP Affiliates	7.7	8.6	20.4	20
Other Revenues	0.4	0.6	1.4	1.6
TOTAL REVENUES	517.6	539.7	1,343.6	1,345.7
Expenses
Fuel and Other Consumables Used for Electric Generation	147.5	158.8	389.8	403.3
Purchased Electricity for Resale	40	35.9	118.7	97.5
Other Operation	80.3	89.2	232.2	243.3
Maintenance	32.6	33.8	106.5	102
Depreciation and Amortization	55.2	51.2	158.1	148.1
Taxes Other Than Income Taxes	25	23.4	72.6	66.8
TOTAL EXPENSES	380.6	392.3	1,077.9	1,061
OPERATING INCOME (LOSS)	137	147.4	265.7	284.7
Other Income (Expense):
Interest Income	0.7	0	2	0
Allowance for Equity Funds Used During Construction	0.4	0.1	1.2	9.5
Interest Expense	(31.9)	(32.6)	(92.7)	(92)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	106.2	114.9	176.2	202.2
Income Tax Expense (Credit)	22.5	33.2	45.2	53.9
Equity Earnings (Loss) of Unconsolidated Subsidiaries	0.4	2.7	(4.5)	4.9
Net Income (Loss)	84.1	84.4	126.5	153.2
Net Income Attributable to Noncontrolling Interests	11	1.1	12.6	3.3
Earnings Attributable to Common Shareholders	$ 73.1	$ 83.3	$ 113.9	$ 149.9

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net Income (Loss)	$ 556.7	$ (764.2)	$ 1,527.1	$ 242.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(15)	(28.6)	(22.6)	(20.8)
Securities Available for Sale, Net of Tax	0.9	0.5	2.7	1.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.3	0.2	0.8	0.4
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(13.8)	(27.9)	(19.1)	(18.7)
TOTAL COMPREHENSIVE INCOME (LOSS)	542.9	(792.1)	1,508	224.1
Total Comprehensive Income Attributable to Noncontrolling Interest	12	1.6	15.2	5.3
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	530.9	(793.7)	1,492.8	218.8
AEP Transmission Co [Member]
Net Income (Loss)	59.9	52.4	224.3	153
Appalachian Power Co [Member]
Net Income (Loss)	86	104.1	248.7	303.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.1)	(0.2)	(0.5)	(0.6)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.3)	(0.3)	(0.9)	(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.4)	(0.5)	(1.4)	(1.6)
TOTAL COMPREHENSIVE INCOME (LOSS)	85.6	103.6	247.3	302.2
Indiana Michigan Power Co [Member]
Net Income (Loss)	64.9	75.4	143.8	201.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.3	0.3	1	1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.3	1	1
TOTAL COMPREHENSIVE INCOME (LOSS)	65.2	75.7	144.8	202.4
Ohio Power Co [Member]
Net Income (Loss)	82.6	99.9	231.1	244.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.3)	(0.2)	(0.8)	(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(0.8)	(1)
TOTAL COMPREHENSIVE INCOME (LOSS)	82.3	99.7	230.3	243.7
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	46.2	52.8	71.4	97.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.2)	(0.6)	(0.6)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(0.6)	(0.6)
TOTAL COMPREHENSIVE INCOME (LOSS)	46	52.6	70.8	96.8
Southwestern Electric Power Co [Member]
Net Income (Loss)	84.1	84.4	126.5	153.2
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.4	0.4	1.1	1.3
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.2)	(0.1)	(0.5)	(0.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.2	0.3	0.6	0.8
TOTAL COMPREHENSIVE INCOME (LOSS)	84.3	84.7	127.1	154
Total Comprehensive Income Attributable to Noncontrolling Interest	11	1.1	12.6	3.3
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 73.3	$ 83.6	$ 114.5	$ 150.7

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Cash Flow Hedges, Tax	$ (8.1)	$ (15.4)	$ (12.2)	$ (11.2)
Securities Available for Sale, Tax	0.5	0.3	1.5	1
Amortization of Pension and OPEB Deferred Costs, Tax	0.1	0.1	0.4	0.2
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.3)	(0.3)
Amortization of Pension and OPEB Deferred Costs, Tax	(0.1)	(0.1)	(0.4)	(0.5)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.1	0.5	0.5
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.4)	(0.5)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.3)	(0.3)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.2	0.2	0.6	0.7
Amortization of Pension and OPEB Deferred Costs, Tax	$ (0.1)	$ (0.1)	$ (0.3)	$ (0.3)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	AEP Transmission Co [Member]	Appalachian Power Co [Member]	Indiana Michigan Power Co [Member]	Ohio Power Co [Member]	Public Service Co Of Oklahoma [Member]	Southwestern Electric Power Co [Member]	Common Stock [Member]	Common Stock [Member]Appalachian Power Co [Member]	Common Stock [Member]Indiana Michigan Power Co [Member]	Common Stock [Member]Ohio Power Co [Member]	Common Stock [Member]Public Service Co Of Oklahoma [Member]	Common Stock [Member]Southwestern Electric Power Co [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]AEP Transmission Co [Member]	Additional Paid-in Capital [Member]Appalachian Power Co [Member]	Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member]	Additional Paid-in Capital [Member]Ohio Power Co [Member]	Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member]	Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member]	Retained Earnings [Member]	Retained Earnings [Member]AEP Transmission Co [Member]	Retained Earnings [Member]Appalachian Power Co [Member]	Retained Earnings [Member]Indiana Michigan Power Co [Member]	Retained Earnings [Member]Ohio Power Co [Member]	Retained Earnings [Member]Public Service Co Of Oklahoma [Member]	Retained Earnings [Member]Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]	Accumulated Other Comprehensive Income [Member]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		$ 1,552.9													$ 1,243							$ 309.9
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	34.2							$ 4.3						29.9
Issuance of Common Stock, Shares								600,000
Common Stock Dividends	(829.8)																				(826.4)
Common Stock Dividends			(225)	(93.8)	(150)		(90)																(225)	(93.8)	(150)		(90)
Common Stock Dividends							(3.5)																											(3.4)	(3.5)
Other Changes in Equity	9.6													3.6																				6
Capital Contributions from Member		116													116
Net Income (Loss)	237.5						149.9														237.5						149.9
Net Income Attributable to Noncontrolling Interests	5.3						3.3																											5.3	3.3
Net Income (Loss)	242.8	153	303.8	201.4	244.7	97.4	153.2															153	303.8	201.4	244.7	97.4
Other Comprehensive Income (Loss)	(18.7)		(1.6)	1	(1)	(0.6)	0.8																					(18.7)	(1.6)	1	(1)	(0.6)	0.8
Ending Balance at Sep. 30, 2016		1,821.9													1,359							462.9
Ending Balance at Sep. 30, 2016	17,343		3,552.2	2,145	2,080.3	1,216.7	2,230.2	$ 3,328.3	260.4	56.6	321.2	157.2	135.7	6,330		1,828.7	980.9	838.8	364	676.6	7,809.4		1,467.5	1,123.2	917	691.9	1,426.2	(145.8)	(4.4)	(15.7)	3.3	3.6	(8.6)	21.1	0.3
Ending Balance, Shares at Sep. 30, 2016								512,000,000
Beginning Balance at Dec. 31, 2016		1,957.6													1,455							502.6
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	$ (875)																				(872.3)
Common Stock Dividends			(90)	(93.7)	(130)	$ (52.5)	(82.5)																(90)	(93.7)	(130)	(52.5)	(82.5)
Common Stock Dividends							(2.7)																											(2.7)	(2.7)
Other Changes in Equity	52.4													51.6																				0.8
Capital Contributions from Member		185.5													185.5
Net Income (Loss)	1,511.9						113.9														1,511.9						113.9
Net Income Attributable to Noncontrolling Interests	15.2						12.6																											15.2	12.6
Net Income (Loss)	1,527.1	224.3	248.7	143.8	231.1	71.4	126.5															224.3	248.7	143.8	231.1	71.4
Other Comprehensive Income (Loss)	(19.1)		(1.4)	1	(0.8)	(0.6)	0.6																					(19.1)	(1.4)	1	(0.8)	(0.6)	0.6
Ending Balance at Sep. 30, 2017		$ 2,367.4													$ 1,640.5							$ 726.9
Ending Balance at Sep. 30, 2017	$ 18,105.5		$ 3,740.8	$ 2,202.9	$ 2,217.8	$ 1,232.4	$ 2,257.1	$ 3,328.3	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,384.2		$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 8,532		$ 1,661.5	$ 1,180.6	$ 1,055.6	$ 708.4	$ 1,443.3	$ (175.4)	$ (9.8)	$ (15.2)	$ 2.2	$ 2.8	$ (8.8)	$ 36.4	$ 10.3
Ending Balance, Shares at Sep. 30, 2017	512,048,663					10,482,000		512,000,000

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents		$ 343.9	$ 210.5
Other Temporary Investments		310.7	331.7
Accounts Receivable:
Customers		522.7	705.1
Accrued Unbilled Revenues		187.3	158.7
Pledged Accounts Receivable - AEP Credit		967.6	972.7
Miscellaneous		99.9	118.1
Allowance for Uncollectible Accounts		(36.6)	(37.9)
Total Accounts Receivable		1,740.9	1,916.7
Fuel		354.2	423.8
Materials and Supplies		562.3	543.5
Risk Management Assets		146.1	94.5
Regulatory Asset for Under-Recovered Fuel Costs		153.5	156.6
Margin Deposits		105.7	79.9
Assets Held for Sale		0	1,951.2
Prepayments and Other Current Assets		350.5	325.5
TOTAL CURRENT ASSETS		4,067.8	6,033.9
Property, Plant and Equipment
Generation		20,739.3	19,848.9
Transmission		17,785.4	16,658.7
Distribution		19,589.4	18,900.8
Other Property, Plant and Equipment		3,614.1	3,444.3
Construction Work in Progress		3,710	3,183.9
Total Property, Plant and Equipment		65,438.2	62,036.6
Accumulated Depreciation and Amortization		17,121.7	16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		48,316.5	45,639.3
Other Noncurrent Assets
Regulatory Assets		5,640	5,625.5
Securitized Assets		1,287.8	1,486.1
Spent Nuclear Fuel and Decommissioning Trusts		2,433	2,256.2
Goodwill		52.5	52.5
Long-term Risk Management Assets		310.4	289.1
Deferred Charges and Other Noncurrent Assets		1,856.9	2,085.1
TOTAL OTHER NONCURRENT ASSETS		11,580.6	11,794.5
TOTAL ASSETS		63,964.9	63,467.7
Current Liabilities
Accounts Payable		1,537	1,688.5
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	750	673
Other Short-term Debt		309.3	1,040
Total Short-term Debt		1,059.3	1,713
Long-term Debt Due Within One Year		2,359.3	2,878
Risk Management Liabilities		69.4	53.4
Customer Deposits		346.6	343.2
Accrued Taxes		716.5	1,048
Accrued Interest		260.3	227.2
Regulatory Liability for Over-Recovered Fuel Costs		19.7	8
Liabilities Held for Sale		0	235.9
Other Current Liabilities		953.9	1,302.8
TOTAL CURRENT LIABILITIES		7,322	9,498
Noncurrent Liabilities
Long-term Debt		18,362.4	17,378.4
Long-term Risk Management Liabilities		352.7	316.2
Deferred Income Taxes		12,628.2	11,884.4
Regulatory Liabilities and Deferred Investment Tax Credits		3,959.6	3,751.3
Asset Retirement Obligations		1,919.3	1,830.6
Employee Benefits and Pension Obligations		468.9	614.1
Deferred Credits and Other Noncurrent Liabilities		837	774.6
TOTAL NONCURRENT LIABILITIES		38,528.1	36,549.6
TOTAL LIABILITIES		45,850.1	46,047.6
Rate Matters
Commitments and Contingencies
Mezzanine Equity		9.3	0
Equity
Common Stock		3,328.3	3,328.3
Paid-in Capital		6,384.2	6,332.6
Retained Earnings		8,532	7,892.4
Accumulated Other Comprehensive Income (Loss)		(175.4)	(156.3)
TOTAL COMMON SHAREHOLDER'S EQUITY		18,069.1	17,397
Noncontrolling Interests		36.4	23.1
TOTAL EQUITY		18,105.5	17,420.1
TOTAL LIABILITIES AND EQUITY		63,964.9	63,467.7
AEP Transmission Co [Member]
Current Assets
Cash and Cash Equivalents		0	0
Advances to Affiliates		290.9	67.1
Accounts Receivable:
Customers		19.5	11.3
Affiliated Companies		102.8	66.6
Total Accounts Receivable		122.3	77.9
Materials and Supplies		16	5
Accrued Tax Benefits		12.7	26
Prepayments and Other Current Assets		8.1	2.8
TOTAL CURRENT ASSETS		450	178.8
Property, Plant and Equipment
Transmission		4,570.9	3,973.5
Other Property, Plant and Equipment		113.5	99.4
Construction Work in Progress		1,383.1	981.3
Total Property, Plant and Equipment		6,067.5	5,054.2
Accumulated Depreciation and Amortization		151.5	99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,916	4,954.6
Other Noncurrent Assets
Accounts Receivable, Related Parties, Noncurrent		13.8	0
Regulatory Assets		138	112.3
Deferred Tax Assets, Property, Plant and Equipment		29.8	102.2
Deferred Charges and Other Noncurrent Assets		1.3	1.9
TOTAL OTHER NONCURRENT ASSETS		182.9	216.4
TOTAL ASSETS		6,548.9	5,349.8
Current Liabilities
Advances from Affiliates		32.8	4.1
Accounts Payable		233.2	289.7
Affiliated Companies		50	43.1
Short-term Debt:
Accrued Taxes		112.5	191.8
Accrued Interest		28.9	10.5
Other Current Liabilities		10.4	10.9
TOTAL CURRENT LIABILITIES		467.8	550.1
Noncurrent Liabilities
Long-term Debt		2,550	1,932
Deferred Income Taxes		1,073.1	862.1
Regulatory Liabilities and Deferred Investment Tax Credits		60.5	44
Deferred Credits and Other Noncurrent Liabilities		30.1	4
TOTAL NONCURRENT LIABILITIES		3,713.7	2,842.1
TOTAL LIABILITIES		4,181.5	3,392.2
Rate Matters
Commitments and Contingencies
Equity
Paid-in Captial		1,640.5	1,455
Retained Earnings		726.9	502.6
TOTAL MEMBER'S EQUITY		2,367.4	1,957.6
TOTAL LIABILITIES AND EQUITY		6,548.9	5,349.8
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.9	2.7
Restricted Cash for Securitized Funding		8.3	15.8
Advances to Affiliates		23.6	24.1
Accounts Receivable:
Customers		96.8	131.4
Affiliated Companies		59.5	54.4
Accrued Unbilled Revenues		41.1	52.7
Miscellaneous		1.3	0.9
Allowance for Uncollectible Accounts		(2.7)	(3.5)
Total Accounts Receivable		196	235.9
Fuel		96.3	112
Materials and Supplies		100.8	98.8
Risk Management Assets		30.3	2.6
Accrued Tax Benefits		0.4	4.2
Regulatory Asset for Under-Recovered Fuel Costs		63.5	68.4
Margin Deposits		11.8	17.5
Prepayments and Other Current Assets		18.2	9.7
TOTAL CURRENT ASSETS		552.1	591.7
Property, Plant and Equipment
Generation		6,393.7	6,332.8
Transmission		2,904.4	2,796.9
Distribution		3,703.5	3,569.1
Other Property, Plant and Equipment		409.8	373.5
Construction Work in Progress		493.5	390.3
Total Property, Plant and Equipment		13,904.9	13,462.6
Accumulated Depreciation and Amortization		3,836.7	3,636.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,068.2	9,825.8
Other Noncurrent Assets
Regulatory Assets		1,100.1	1,121.1
Securitized Assets		288	305.3
Long-term Risk Management Assets		0.6	0
Deferred Charges and Other Noncurrent Assets		113.6	133.3
TOTAL OTHER NONCURRENT ASSETS		1,502.3	1,559.7
TOTAL ASSETS		12,122.6	11,977.2
Current Liabilities
Advances from Affiliates		69.5	79.6
Accounts Payable		235.4	253.7
Affiliated Companies		75.5	82.6
Short-term Debt:
Long-term Debt Due Within One Year		149.2	503.1
Risk Management Liabilities		0.9	0.3
Customer Deposits		84	83.1
Accrued Taxes		64	107.6
Accrued Interest		71.4	40.6
Other Current Liabilities		99.2	129.5
TOTAL CURRENT LIABILITIES		849.1	1,280.1
Noncurrent Liabilities
Long-term Debt		3,830.1	3,530.8
Long-term Risk Management Liabilities		0.3	0.9
Deferred Income Taxes		2,796.7	2,672.3
Regulatory Liabilities and Deferred Investment Tax Credits		634.4	627.8
Asset Retirement Obligations		101.2	108.8
Employee Benefits and Pension Obligations		92.2	108.5
Deferred Credits and Other Noncurrent Liabilities		77.8	64.5
TOTAL NONCURRENT LIABILITIES		7,532.7	7,113.6
TOTAL LIABILITIES		8,381.8	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		1,661.5	1,502.8
Accumulated Other Comprehensive Income (Loss)		(9.8)	(8.4)
TOTAL EQUITY		3,740.8	3,583.5
TOTAL LIABILITIES AND EQUITY		12,122.6	11,977.2
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.3	1.2
Advances to Affiliates		12.6	12.5
Accounts Receivable:
Customers		42.1	60.2
Affiliated Companies		42.8	51
Accrued Unbilled Revenues		8.4	1.5
Miscellaneous		1.1	0.7
Allowance for Uncollectible Accounts		(0.3)	0
Total Accounts Receivable		94.1	113.4
Fuel		32.3	32.3
Materials and Supplies		156.5	150.8
Risk Management Assets		11.6	3.5
Accrued Tax Benefits		34.5	37.7
Regulatory Asset for Under-Recovered Fuel Costs		12.3	26.1
Accrued Reimbursement of Spent Nuclear Fuel Costs		11	22.1
Prepayments and Other Current Assets		26.9	19.9
TOTAL CURRENT ASSETS		393.1	419.5
Property, Plant and Equipment
Generation		4,399.9	4,056.1
Transmission		1,491.4	1,472.8
Distribution		2,000.1	1,899.3
Other Property, Plant and Equipment		555.9	550.2
Construction Work in Progress		478.9	654.2
Total Property, Plant and Equipment		8,926.2	8,632.6
Accumulated Depreciation and Amortization		3,022.5	3,005.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,903.7	5,627.5
Other Noncurrent Assets
Regulatory Assets		941	916.6
Spent Nuclear Fuel and Decommissioning Trusts		2,433	2,256.2
Long-term Risk Management Assets		0.5	0
Deferred Charges and Other Noncurrent Assets		95.9	121.5
TOTAL OTHER NONCURRENT ASSETS		3,470.4	3,294.3
TOTAL ASSETS		9,767.2	9,341.3
Current Liabilities
Advances from Affiliates		177.5	215.2
Accounts Payable		168.6	179
Affiliated Companies		72.2	75.6
Short-term Debt:
Long-term Debt Due Within One Year		462.1	209.3
Risk Management Liabilities		2	0.3
Customer Deposits		37.3	34.3
Accrued Taxes		43.8	77.2
Accrued Interest		14.3	31.7
Obligations Under Capital Leases		7.3	9.4
Other Current Liabilities		114.3	123.4
TOTAL CURRENT LIABILITIES		1,099.4	955.4
Noncurrent Liabilities
Long-term Debt		2,196.4	2,262.1
Long-term Risk Management Liabilities		0.2	0.8
Deferred Income Taxes		1,681.8	1,527.4
Regulatory Liabilities and Deferred Investment Tax Credits		1,169.6	1,065.5
Asset Retirement Obligations		1,307.4	1,257.9
Deferred Credits and Other Noncurrent Liabilities		109.5	120.4
TOTAL NONCURRENT LIABILITIES		6,464.9	6,234.1
TOTAL LIABILITIES		7,564.3	7,189.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,180.6	1,130.5
Accumulated Other Comprehensive Income (Loss)		(15.2)	(16.2)
TOTAL EQUITY		2,202.9	2,151.8
TOTAL LIABILITIES AND EQUITY		9,767.2	9,341.3
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.1	3.1
Restricted Cash for Securitized Funding		15.6	27.2
Advances to Affiliates		0	24.2
Accounts Receivable:
Customers		27.1	51.1
Affiliated Companies		72	66.3
Accrued Unbilled Revenues		24.2	21
Miscellaneous		1.1	0.9
Allowance for Uncollectible Accounts		(0.4)	(0.4)
Total Accounts Receivable		124	138.9
Materials and Supplies		42.8	45.9
Emission Allowances		23.6	20.4
Risk Management Assets		0.2	0.2
Accrued Tax Benefits		15.4	0.1
Prepayments and Other Current Assets		28.1	10.9
TOTAL CURRENT ASSETS		252.8	270.9
Property, Plant and Equipment
Transmission		2,349.5	2,319.2
Distribution		4,575	4,457.2
Other Property, Plant and Equipment		487.9	443.7
Construction Work in Progress		350.7	221.5
Total Property, Plant and Equipment		7,763.1	7,441.6
Accumulated Depreciation and Amortization		2,182.8	2,116
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,580.3	5,325.6
Other Noncurrent Assets
Notes Receivable - Affiliated		32.3	32.3
Regulatory Assets		1,014.7	1,107.5
Securitized Assets		43.7	62.1
Deferred Charges and Other Noncurrent Assets		131.2	295.5
TOTAL OTHER NONCURRENT ASSETS		1,221.9	1,497.4
TOTAL ASSETS		7,055	7,093.9
Current Liabilities
Advances from Affiliates		167.6	0
Accounts Payable		157.8	175.4
Affiliated Companies		95.3	95.6
Short-term Debt:
Long-term Debt Due Within One Year		397	46.4
Risk Management Liabilities		7.6	5.9
Customer Deposits		62.9	71
Accrued Taxes		251.3	520.3
Accrued Interest		38.3	31.2
Other Current Liabilities		166.3	236
TOTAL CURRENT LIABILITIES		1,344.1	1,181.8
Noncurrent Liabilities
Long-term Debt		1,321.9	1,717.5
Long-term Risk Management Liabilities		130.9	113.1
Deferred Income Taxes		1,460.7	1,346.1
Regulatory Liabilities and Deferred Investment Tax Credits		519.3	506.2
Employee Benefits and Pension Obligations		19.3	27.8
Deferred Credits and Other Noncurrent Liabilities		41	83.9
TOTAL NONCURRENT LIABILITIES		3,493.1	3,794.6
TOTAL LIABILITIES		4,837.2	4,976.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		1,055.6	954.5
Accumulated Other Comprehensive Income (Loss)		2.2	3
TOTAL EQUITY		2,217.8	2,117.5
TOTAL LIABILITIES AND EQUITY		7,055	7,093.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		2.1	1.5
Accounts Receivable:
Customers		17.8	27.5
Affiliated Companies		31.8	26.8
Miscellaneous		3.2	4.4
Allowance for Uncollectible Accounts		(0.1)	(0.2)
Total Accounts Receivable		52.7	58.5
Fuel		11.9	22.9
Materials and Supplies		42.1	44.6
Risk Management Assets		4.7	0.8
Accrued Tax Benefits		27	27.3
Regulatory Asset for Under-Recovered Fuel Costs		36.9	33.8
Prepayments and Other Current Assets		14.4	6
TOTAL CURRENT ASSETS		191.8	195.4
Property, Plant and Equipment
Generation		1,573.8	1,559.3
Transmission		852.5	832.8
Distribution		2,414.1	2,322.4
Other Property, Plant and Equipment		286.3	233.2
Construction Work in Progress		114	148.2
Total Property, Plant and Equipment		5,240.7	5,095.9
Accumulated Depreciation and Amortization		1,382.8	1,272.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,857.9	3,823.2
Other Noncurrent Assets
Regulatory Assets		393.6	340.2
Employee Benefits and Pension Assets		16	10.4
Deferred Charges and Other Noncurrent Assets		19.2	10
TOTAL OTHER NONCURRENT ASSETS		428.8	360.6
TOTAL ASSETS		4,478.5	4,379.2
Current Liabilities
Advances from Affiliates		118	52
Accounts Payable		93.8	116.3
Affiliated Companies		43	56.2
Short-term Debt:
Long-term Debt Due Within One Year		0.5	0.5
Customer Deposits		53.1	49.7
Accrued Taxes		40.8	21
Accrued Interest		19.5	13.9
Provision for Refund		4.1	46.1
Other Current Liabilities		38.5	47.8
TOTAL CURRENT LIABILITIES		411.3	403.5
Noncurrent Liabilities
Long-term Debt		1,285.9	1,285.5
Deferred Income Taxes		1,152.5	1,058.8
Regulatory Liabilities and Deferred Investment Tax Credits		320.9	339.7
Asset Retirement Obligations		54.5	52.8
Deferred Credits and Other Noncurrent Liabilities		21	24.8
TOTAL NONCURRENT LIABILITIES		2,834.8	2,761.6
TOTAL LIABILITIES		3,246.1	3,165.1
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		708.4	689.5
Accumulated Other Comprehensive Income (Loss)		2.8	3.4
TOTAL EQUITY		1,232.4	1,214.1
TOTAL LIABILITIES AND EQUITY		4,478.5	4,379.2
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.2	10.3
Advances to Affiliates		2	169.8
Accounts Receivable:
Customers		23.5	48.5
Affiliated Companies		37.6	29.3
Miscellaneous		20.8	17.5
Allowance for Uncollectible Accounts		(1.5)	(1.2)
Total Accounts Receivable		80.4	94.1
Fuel		93.1	107.1
Materials and Supplies		68.8	68.4
Risk Management Assets		12.5	0.9
Accrued Tax Benefits		14.5	51.5
Regulatory Asset for Under-Recovered Fuel Costs		13.6	8.4
Prepayments and Other Current Assets		35.5	35.5
TOTAL CURRENT ASSETS		322.6	546
Property, Plant and Equipment
Generation		4,632.9	4,607.6
Transmission		1,656.4	1,584.2
Distribution		2,084.2	2,020.6
Other Property, Plant and Equipment		701.6	670.4
Construction Work in Progress		145.2	113.8
Total Property, Plant and Equipment		9,220.3	8,996.6
Accumulated Depreciation and Amortization		2,670.5	2,567.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,549.8	6,429.5
Other Noncurrent Assets
Regulatory Assets		566.4	551.2
Long-term Risk Management Assets		0.7	0
Deferred Charges and Other Noncurrent Assets		116.4	99.9
TOTAL OTHER NONCURRENT ASSETS		683.5	651.1
TOTAL ASSETS		7,555.9	7,626.6
Current Liabilities
Advances from Affiliates		48.3	0
Accounts Payable		120.9	117.5
Affiliated Companies		38.5	68.5
Short-term Debt:
Other Short-term Debt		14.3	0
Long-term Debt Due Within One Year		385.4	353.7
Risk Management Liabilities		0.1	0.3
Customer Deposits		61.6	62.1
Accrued Taxes		73	40.9
Accrued Interest		25.1	45.1
Obligations Under Capital Leases		11.4	11.8
Other Current Liabilities		77.5	83.9
TOTAL CURRENT LIABILITIES		856.1	783.8
Noncurrent Liabilities
Long-term Debt		2,056.1	2,325.4
Deferred Income Taxes		1,694.5	1,606.9
Regulatory Liabilities and Deferred Investment Tax Credits		441.3	438.9
Asset Retirement Obligations		159	147.1
Employee Benefits and Pension Obligations		19.9	34.1
Obligations Under Capital Leases		60.2	65.5
Deferred Credits and Other Noncurrent Liabilities		11.7	9.7
TOTAL NONCURRENT LIABILITIES		4,442.7	4,627.6
TOTAL LIABILITIES		5,298.8	5,411.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,443.3	1,411.9
Accumulated Other Comprehensive Income (Loss)		(8.8)	(9.4)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,246.8	2,214.8
Noncontrolling Interests		10.3	0.4
TOTAL EQUITY		2,257.1	2,215.2
TOTAL LIABILITIES AND EQUITY		$ 7,555.9	$ 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	Sep. 30, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	$ 343.9	$ 210.5
Other Temporary Investments	310.7	331.7
Fuel	354.2	423.8
Property, Plant and Equipment
Other Property, Plant and Equipment	3,614.1	3,444.3
Accumulated Depreciation and Amortization	17,121.7	16,397.3
Current Liabilities
Long-term Debt Due Within One Year	2,359.3	2,878
Noncurrent Liabilities
Long-term Debt	$ 18,362.4	$ 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	20,206,368	20,336,592
AEP Subsidiaries [Member]
Current Assets
Other Temporary Investments	$ 300.5	$ 322.5
Current Liabilities
Long-term Debt Due Within One Year	393.7	427.5
Noncurrent Liabilities
Long-term Debt	1,421.5	1,737.5
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	2.9	2.7
Fuel	96.3	112
Property, Plant and Equipment
Other Property, Plant and Equipment	409.8	373.5
Accumulated Depreciation and Amortization	3,836.7	3,636.8
Current Liabilities
Long-term Debt Due Within One Year	149.2	503.1
Noncurrent Liabilities
Long-term Debt	$ 3,830.1	$ 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	$ 1.3	$ 1.2
Fuel	32.3	32.3
Property, Plant and Equipment
Other Property, Plant and Equipment	555.9	550.2
Accumulated Depreciation and Amortization	3,022.5	3,005.1
Current Liabilities
Long-term Debt Due Within One Year	462.1	209.3
Noncurrent Liabilities
Long-term Debt	$ 2,196.4	$ 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	$ 83.7	$ 130.9
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3.1	3.1
Property, Plant and Equipment
Other Property, Plant and Equipment	487.9	443.7
Accumulated Depreciation and Amortization	2,182.8	2,116
Current Liabilities
Long-term Debt Due Within One Year	397	46.4
Noncurrent Liabilities
Long-term Debt	$ 1,321.9	$ 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	$ 47	$ 46.3
Noncurrent Liabilities
Long-term Debt	47.5	93.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	2.1	1.5
Fuel	11.9	22.9
Property, Plant and Equipment
Other Property, Plant and Equipment	286.3	233.2
Accumulated Depreciation and Amortization	1,382.8	1,272.7
Current Liabilities
Long-term Debt Due Within One Year	0.5	0.5
Noncurrent Liabilities
Long-term Debt	$ 1,285.9	$ 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	$ 2.2	$ 10.3
Fuel	93.1	107.1
Property, Plant and Equipment
Other Property, Plant and Equipment	701.6	670.4
Accumulated Depreciation and Amortization	2,670.5	2,567.1
Current Liabilities
Long-term Debt Due Within One Year	385.4	353.7
Noncurrent Liabilities
Long-term Debt	$ 2,056.1	$ 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	$ 0	$ 8.7
Fuel	43.2	34.3
Property, Plant and Equipment
Other Property, Plant and Equipment	266.6	267.5
Accumulated Depreciation and Amortization	$ 162.8	$ 155.6

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating Activities
Net Income (Loss)	$ 1,527.1	$ 242.8
Income (Loss) from Discontinued Operations	0	(2.5)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	1,527.1	245.3
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	1,485.9	1,550.2
Deferred Income Taxes	740.9	(47)
Asset Impairments and Other Related Charges	10.6	2,264.9
Carrying Costs Income	(14.2)	(11.9)
Allowance for Equity Funds Used During Construction	(62.2)	(86.1)
Mark-to-Market of Risk Management Contracts	(56.2)	56.6
Amortization of Nuclear Fuel	104.8	109.7
Pension Contributions to Qualified Plan Trust	(93.3)	(84.8)
Property Taxes	291.4	288.3
Deferred Fuel Over/Under-Recovery, Net	81	(28.5)
Gain on Sale of Merchant Generation Assets	(226.4)	0
Gain on Sale of Equity Investment	(12.4)	0
Recovery of Ohio Capacity Costs, Net	65.6	108.8
Provision for Refund - Global Settlement	(93.3)	0
Change in Other Noncurrent Assets	(345.2)	(243.4)
Change in Other Noncurrent Liabilities	205.7	41.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	201.3	(240.8)
Fuel, Materials and Supplies	58.5	11.6
Accounts Payable	(91)	47.8
Accrued Taxes, Net	(310.1)	(393)
Other Current Assets	(98.2)	31.5
Other Current Liabilities	(260.3)	(211.4)
Net Cash Flows from (Used for) Operating Activities	3,124.2	3,421
Investing Activities
Construction Expenditures	(3,778.2)	(3,387)
Change In Other Temporary Investments, Net	34.5	109.2
Purchases of Investment Securities	(1,855.8)	(2,454.5)
Sales of Investment Securities	1,808.6	2,427
Acquisitions of Nuclear Fuel	(73.2)	(127.6)
Proceeds From Sale Of Merchant Generation Assets	2,159.6	0
Other Investing Activities	27.9	4.2
Net Cash Flows from (Used for) Continuing Investing Activities	(1,676.6)	(3,428.7)
Financing Activities
Issuance of Common Stock, Net	0	34.2
Issuance of Long-term Debt	2,742.7	1,559.6
Change in Short-term Debt, Net	(653.7)	678.3
Retirement of Long-term Debt	(2,427.2)	(1,307.6)
Make Whole Premium on Extinguishment of Long-term Debt	(46.1)	0
Principal Payments for Capital Lease Obligations	(50.5)	(81.9)
Dividends Paid on Common Stock	(875)	(829.8)
Other Financing Activities	(4.4)	(6.8)
Net Cash Flows from (Used for) Financing Activities	(1,314.2)	46
Cash Flows from Discontinued Operations
Operating Activities	0	(2.5)
Investing Activities	0	0
Financing Activities	0	0
Net Increase (Decrease) in Cash and Cash Equivalents	133.4	35.8
Cash and Cash Equivalents at Beginning of Period	210.5	176.4
Cash and Cash Equivalents at End of Period	343.9	212.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	613.8	637
Net Cash Paid (Received) for Income Taxes	(6.8)	32.2
Noncash Acquisitions Under Capital Leases	44.5	65.8
Construction Expenditures Included in Current Liabilities as of September 30,	791.6	604.8
Construction Expenditures Included in Noncurrent Liabilities as of September 30,	71.8	0
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	0.6	0.3
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	2.8	0
AEP Transmission Co [Member]
Operating Activities
Net Income (Loss)	224.3	153
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	70.9	47.5
Deferred Income Taxes	193	161.2
Allowance for Equity Funds Used During Construction	(36)	(39.7)
Property Taxes	72.4	63.5
Long-term Accounts Receivable - Affiliated	(13.8)	0
Change in Other Noncurrent Assets	7.6	(6.4)
Change in Other Noncurrent Liabilities	25.7	0.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(44.4)	(43.3)
Fuel, Materials and Supplies	(11)	(1.5)
Accounts Payable	8.6	(1.7)
Accrued Taxes, Net	(66)	61.2
Accrued Interest	18.4	11.3
Other Current Assets	(5.3)	(0.1)
Other Current Liabilities	0.5	0.1
Net Cash Flows from (Used for) Operating Activities	444.9	405.7
Investing Activities
Construction Expenditures	(1,050.7)	(799.8)
Change in Advances to Affiliates, Net	(223.8)	83.7
Other Investing Activities	(2.9)	(4.6)
Net Cash Flows from (Used for) Investing Activities	(1,277.4)	(720.7)
Financing Activities
Capital Contributions from Member	185.5	116
Issuance of Long-term Debt	618.3	0
Change in Advances from Affiliates, Net	28.7	199
Net Cash Flows from (Used for) Financing Activities	832.5	315
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0	0
Cash and Cash Equivalents at Beginning of Period	0	0
Cash and Cash Equivalents at End of Period	0	0
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	28.6	20
Net Cash Paid (Received) for Income Taxes	(93.4)	(209.8)
Construction Expenditures Included in Current Liabilities as of September 30,	239	204.8
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	248.7	303.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	304.1	290
Deferred Income Taxes	121.7	100.9
Carrying Costs Income	(1)	(0.2)
Allowance for Equity Funds Used During Construction	(6.2)	(9.1)
Mark-to-Market of Risk Management Contracts	(28.3)	18.4
Pension Contributions to Qualified Plan Trust	(10.2)	(8.8)
Property Taxes	29.8	29.2
Deferred Fuel Over/Under-Recovery, Net	4.9	19
Change in Other Noncurrent Assets	8.3	(5.1)
Change in Other Noncurrent Liabilities	7.9	(23)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	39.9	(20.5)
Fuel, Materials and Supplies	14	(1.2)
Accounts Payable	6.2	4.9
Accrued Taxes, Net	(44.2)	(13.9)
Other Current Assets	(2.5)	(0.2)
Other Current Liabilities	9.1	(4.1)
Net Cash Flows from (Used for) Operating Activities	702.2	680.1
Investing Activities
Construction Expenditures	(560)	(472.7)
Change in Restricted Cash for Securitized Funding	7.5	7
Change in Advances to Affiliates, Net	0.5	1.2
Other Investing Activities	11.8	10.6
Net Cash Flows from (Used for) Investing Activities	(540.2)	(453.9)
Financing Activities
Issuance of Long-term Debt	320.9	314.1
Change in Advances from Affiliates, Net	(10.1)	(96.9)
Retirement of Long-term Debt	(377.9)	(213.6)
Principal Payments for Capital Lease Obligations	(5.2)	(4.7)
Dividends Paid on Common Stock	(90)	(225)
Other Financing Activities	0.5	0.4
Net Cash Flows from (Used for) Financing Activities	(161.8)	(225.7)
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.2	0.5
Cash and Cash Equivalents at Beginning of Period	2.7	2.8
Cash and Cash Equivalents at End of Period	2.9	3.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	107.1	113.2
Net Cash Paid (Received) for Income Taxes	24.4	55.8
Noncash Acquisitions Under Capital Leases	2.9	2.1
Construction Expenditures Included in Current Liabilities as of September 30,	107.2	66.8
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	143.8	201.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	154.8	143.2
Deferred Income Taxes	132.2	116.2
Deferral of Incremental Nuclear Refueling Outage Expenses, Net	15.5	(17.4)
Asset Impairments and Other Related Charges	0	10.5
Allowance for Equity Funds Used During Construction	(8.1)	(10.9)
Mark-to-Market of Risk Management Contracts	(7.5)	0.5
Amortization of Nuclear Fuel	104.8	109.7
Pension Contributions to Qualified Plan Trust	(13)	(12.7)
Deferred Fuel Over/Under-Recovery, Net	22	6.1
Change in Other Noncurrent Assets	(42.1)	0
Change in Other Noncurrent Liabilities	40.9	30
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	19.3	17
Fuel, Materials and Supplies	(4.1)	(1.1)
Accounts Payable	16.6	(17.9)
Accrued Taxes, Net	(30.2)	(16.5)
Other Current Assets	8	6.7
Other Current Liabilities	(28.6)	(27.8)
Net Cash Flows from (Used for) Operating Activities	524.3	537
Investing Activities
Construction Expenditures	(469.2)	(405.1)
Change in Advances to Affiliates, Net	(0.1)	(0.7)
Purchases of Investment Securities	(1,842.2)	(2,452.9)
Sales of Investment Securities	1,808.6	2,427
Acquisitions of Nuclear Fuel	(73.2)	(127.6)
Other Investing Activities	7.3	7.8
Net Cash Flows from (Used for) Investing Activities	(568.8)	(551.5)
Financing Activities
Issuance of Long-term Debt	411.1	482.7
Change in Advances from Affiliates, Net	(37.7)	(268)
Retirement of Long-term Debt	(227.1)	(76.8)
Principal Payments for Capital Lease Obligations	(8.7)	(29.8)
Dividends Paid on Common Stock	(93.7)	(93.8)
Other Financing Activities	0.7	0.7
Net Cash Flows from (Used for) Financing Activities	44.6	15
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	0.5
Cash and Cash Equivalents at Beginning of Period	1.2	1.1
Cash and Cash Equivalents at End of Period	1.3	1.6
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	92	85.6
Net Cash Paid (Received) for Income Taxes	(69.6)	(36)
Noncash Acquisitions Under Capital Leases	5.9	16.8
Construction Expenditures Included in Current Liabilities as of September 30,	74.5	83.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	0.6	0.3
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	2.8	0.1
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	231.1	244.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	165.7	189
Amortization Of Generation Deferrals	172.9	173
Deferred Income Taxes	117.5	28.6
Carrying Costs Income	(3)	(4)
Allowance for Equity Funds Used During Construction	(4.1)	(3.7)
Mark-to-Market of Risk Management Contracts	19.5	124.7
Pension Contributions to Qualified Plan Trust	(8.2)	(7.1)
Property Taxes	175.9	169.1
Provision for Refund - Global Settlement	(93.3)	0
Change in Other Noncurrent Assets	(126.7)	(124.9)
Change in Other Noncurrent Liabilities	43.4	17.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	14.9	8.8
Fuel, Materials and Supplies	(7.1)	0.5
Accounts Payable	(31.2)	2
Accrued Taxes, Net	(284.3)	(291.1)
Other Current Assets	(17.3)	(5.7)
Other Current Liabilities	(34.8)	(46.8)
Net Cash Flows from (Used for) Operating Activities	330.9	474.3
Investing Activities
Construction Expenditures	(362.5)	(276.4)
Change in Restricted Cash for Securitized Funding	11.6	11.6
Change in Advances to Affiliates, Net	24.2	330.9
Other Investing Activities	6.9	9
Net Cash Flows from (Used for) Investing Activities	(319.8)	75.1
Financing Activities
Change in Advances from Affiliates, Net	167.6	0
Retirement of Long-term Debt	(46.4)	(395.9)
Principal Payments for Capital Lease Obligations	(3.1)	(3.1)
Dividends Paid on Common Stock	(130)	(150)
Other Financing Activities	0.8	0.5
Net Cash Flows from (Used for) Financing Activities	(11.1)	(548.5)
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0	0.9
Cash and Cash Equivalents at Beginning of Period	3.1	3.1
Cash and Cash Equivalents at End of Period	3.1	4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	68.1	78.2
Net Cash Paid (Received) for Income Taxes	69.6	178
Noncash Acquisitions Under Capital Leases	3.6	2.4
Construction Expenditures Included in Current Liabilities as of September 30,	56.8	30
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	71.4	97.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	97.8	109.9
Deferred Income Taxes	93.7	79.5
Allowance for Equity Funds Used During Construction	(0.4)	(4.9)
Mark-to-Market of Risk Management Contracts	(3.9)	(0.7)
Pension Contributions to Qualified Plan Trust	(5.3)	(5.6)
Property Taxes	(9.4)	(8)
Deferred Fuel Over/Under-Recovery, Net	(5.6)	(80.2)
Provision for Refund	(39.4)	13.8
Change in Other Noncurrent Assets	(19.8)	(18.8)
Change in Other Noncurrent Liabilities	(1.4)	(3.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	5.8	4.4
Fuel, Materials and Supplies	13.5	(2.4)
Accounts Payable	(18.5)	23.1
Accrued Taxes, Net	20.1	45.4
Other Current Assets	(8.2)	(2.2)
Other Current Liabilities	1.5	(14.9)
Net Cash Flows from (Used for) Operating Activities	191.9	232.1
Investing Activities
Construction Expenditures	(203.1)	(266.8)
Change in Advances to Affiliates, Net	0	29.5
Other Investing Activities	1.5	8.7
Net Cash Flows from (Used for) Investing Activities	(201.6)	(228.6)
Financing Activities
Issuance of Long-term Debt	0	150
Change in Advances from Affiliates, Net	66	0
Retirement of Long-term Debt	(0.3)	(150.3)
Principal Payments for Capital Lease Obligations	(3.2)	(3)
Dividends Paid on Common Stock	(52.5)	0
Other Financing Activities	0.3	0.4
Net Cash Flows from (Used for) Financing Activities	10.3	(2.9)
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.6	0.6
Cash and Cash Equivalents at Beginning of Period	1.5	1.4
Cash and Cash Equivalents at End of Period	2.1	2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	40.9	45
Net Cash Paid (Received) for Income Taxes	(46.6)	(50.3)
Noncash Acquisitions Under Capital Leases	1	2.2
Construction Expenditures Included in Current Liabilities as of September 30,	15.1	20.2
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)	126.5	153.2
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	158.1	148.1
Deferred Income Taxes	79.8	141.9
Allowance for Equity Funds Used During Construction	(1.2)	(9.5)
Mark-to-Market of Risk Management Contracts	(12.5)	(5.8)
Pension Contributions to Qualified Plan Trust	(8.9)	(8.3)
Property Taxes	(15.4)	(13.7)
Deferred Fuel Over/Under-Recovery, Net	2.4	1.2
Change in Other Noncurrent Assets	(2.9)	18.4
Change in Other Noncurrent Liabilities	(5.2)	(25.8)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	12.1	12.2
Fuel, Materials and Supplies	13.6	33.4
Accounts Payable	(25.7)	(17.2)
Accrued Taxes, Net	69.1	14.1
Accrued Interest	(20)	(20)
Other Current Assets	0.7	(2.4)
Other Current Liabilities	(14.6)	(24.8)
Net Cash Flows from (Used for) Operating Activities	355.9	395
Investing Activities
Construction Expenditures	(265.3)	(315.3)
Change in Advances to Affiliates, Net	167.8	(297.4)
Other Investing Activities	3.1	(1.9)
Net Cash Flows from (Used for) Investing Activities	(94.4)	(614.6)
Financing Activities
Issuance of Long-term Debt	114.6	402.2
Change in Short-term Debt, Net	14.3	0
Change in Advances from Affiliates, Net	48.3	(58.3)
Retirement of Long-term Debt	(353.6)	(3.3)
Principal Payments for Capital Lease Obligations	(8.4)	(18.6)
Dividends Paid on Common Stock	(82.5)	(90)
Dividends Paid on Common Stock	(2.7)	(3.5)
Other Financing Activities	0.4	1.1
Net Cash Flows from (Used for) Financing Activities	(269.6)	229.6
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	(8.1)	10
Cash and Cash Equivalents at Beginning of Period	10.3	5.2
Cash and Cash Equivalents at End of Period	2.2	15.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	109.4	107.6
Net Cash Paid (Received) for Income Taxes	(70.5)	(66.6)
Noncash Acquisitions Under Capital Leases	2.8	5.5
Construction Expenditures Included in Current Liabilities as of September 30,	$ 40.7	$ 54.3

Significant Accounting Matters

Significant Accounting Matters	9 Months Ended
	Sep. 30, 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —
AEP Transmission 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —
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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —
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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —
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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —
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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —
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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49 There were no antidilutive shares outstanding as of September 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the second quarter of 2017 related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6 million . Supplementary Cash Flow Information (Applies to AEP) Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
AEP Transmission 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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.
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 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. The evaluation of revenue streams, new contracts and the new revenue standard’s disclosure requirements continues during the fourth quarter of 2017, in particular with respect to various ongoing industry implementation issues. Management will continue to analyze the related impacts to revenue recognition and monitor any new industry implementation issues that arise. Further, given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. 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 sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. 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 sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with 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 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. Multiple lease system options were also 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. Evaluation of new lease contracts continues and the process of implementing a compliant lease system solution began in the third quarter of 2017. 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 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 statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. For 2016, AEP’s actual non-service cost components were a credit of $66 million , of which approximately 37% was capitalized. 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 plans to adopt ASU 2017-07 effective January 1, 2018. ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12) In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and reduce the complexity of applying hedge accounting. Under the new standard, the concept of recognizing hedge ineffectiveness within the statements of income for cash flow hedges, which has historically been immaterial to AEP, will be eliminated. In addition, certain required tabular disclosures relating to fair value and cash flow hedges will be modified. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted for any interim or annual period after August 2017. Management is analyzing the impact of this new standard, including the possibility of early adoption, and at this time, cannot estimate the impact of adoption on net income.

Comprehensive Income

Comprehensive Income	9 Months Ended
	Sep. 30, 2017
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the condensed financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 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 September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )
Appalachian Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the condensed financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 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 September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )
Indiana Michigan Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the condensed financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 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 September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )
Ohio Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the condensed financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 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 September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )
Public Service Co Of Oklahoma [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the condensed financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 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 September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )
Southwestern Electric Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have any components of other comprehensive income for any period presented in the condensed financial statements. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 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 September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )

Rate Matters

Rate Matters	9 Months Ended
	Sep. 30, 2017
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo
AEP Transmission Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo
Appalachian Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo
Indiana Michigan Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo
Ohio Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo
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 AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo
Southwestern Electric Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018. I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7 OPCo September 30, 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 Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million. SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 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 September 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $697 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. Hurricane Harvey In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of September 30, 2017 , the total balance of AEP Texas’ deferred storm costs is approximately $97 million including approximately $73 million of incremental storm expenses as a regulatory asset related to Hurricane Harvey. Management is currently in the early stages of analyzing the impact of potential insurance claims and recoveries and, at this time, cannot estimate this amount. Any future insurance recoveries received will be applied to and will offset the regulatory asset and property, plant and equipment, as applicable. AEP Texas is currently evaluating recovery options for the regulatory asset; however, management believes the asset is probable of recovery. The other named hurricanes did not have a material impact on AEP’s operations in the third quarter of 2017. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverse effect on future net income, cash flows and 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 September 2017, the Supreme Court of Virginia affirmed the Virginia SCC’s 2016 order. 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. Through September 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $709 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) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project. A hearing at the IURC is scheduled for January 2018. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49 million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022) and a return on common equity of 9.8% . The intervenors proposed certain adjustments to I&M’s request including no change to the current 2044 retirement date of Rockport Plant, Unit 1, but did not propose an annual net revenue increase. Their recommended return on common equity ranged from 9.3% to 9.5% . A hearing at the MPSC is scheduled for November 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. As of September 30, 2017 , total costs incurred related to this project, including AFUDC, were approximately $17 million . 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 I&M and KPCo and will be subject to future regulatory approval for recovery. 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 Plant, Unit 2 lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for the Southern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2. In August 2017, the district court delayed the deadline for installation of the SCR technology until March 2020. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenue request to $60 million . The modification was due to a lower interest expense related to June 2017 debt refinancings. In October 2017, various intervenors filed testimony that included annual net revenue increase recommendations ranging from $13 million to $40 million . Intervenors recommended returns on common equity ranging from 8.6% to 8.85% . Intervenors also recommended significant delays in KPCo’s proposed recoveries of: (a) depreciation expense related to Big Sandy Plant, Unit 1 (gas unit), proposing a 30-year depreciable life instead of KPCo’s proposed 15-year life and (b) lease expense on Rockport Plant, Unit 2 billed from AEGCo, proposing that the approximate $100 million of lease expense for the period 2018 through 2022 be deferred with a WACC carrying charge for recovery over 10 years beginning 2023. Testimony on behalf of the Attorney General also discussed that the KPSC could consider disallowing all or a portion of the costs currently being recovered over 25 years through the Big Sandy Plant, Unit 2 retirement rider. As of September 30, 2017, KPCo’s regulatory asset related to the retired Big Sandy Plant, Unit 2 was $289 million . A hearing at the KPSC is scheduled for December 2017. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the DIR, effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, 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 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. 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 April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In 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 Renewable Resource Rider. In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESP through May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIR ranging from $215 million to $290 million for the periods 2018 through 2021 and (e) the addition of various new riders, including a Smart City Rider and a Renewable Generation Rider. DIR rate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020. In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to not exceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with the conclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation is subject to review by the PUCO. A hearing at the PUCO is scheduled for November 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. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s adjusted 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capital investments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSO requested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of September 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $82 million . In September 2017, various intervenors and the OCC staff filed testimony that included annual net revenue increase recommendations ranging from $28 million to $108 million . The recommended returns on common equity ranged from 8% to 9% . In addition, certain parties recommended investment disallowances that ranged from $27 million to $82 million related to Northeastern Plant, Unit 4 and $38 million associated with capitalized incentives. Also, a party recommended a potential refund of $43 million related to an SPP rider claiming that PSO did not adequately support the related SPP costs. The combined total impact could result in a write-off and refund of up to approximately $163 million . In addition, if similar plant recovery issues would apply to Northeastern Plant, Unit 3, the net book value of plant, including regulatory assets, materials and supplies inventory and CWIP of $346 million as of September 30, 2017 , could be adversely impacted. A hearing at the OCC is scheduled to begin in October 2017. If any of these costs are not recoverable, 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 June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, intervenors filed appeals with the Texas Third Court of Appeals. If certain parts of the PUCT order are overturned and 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 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 and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended returns 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 $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. In September 2017, the Administrative Law Judges (ALJs) issued their proposal for decision including an annual net revenue increase of $50 million including recovery of Welsh Plant, Unit 2 environmental investments as of June 30, 2016. The ALJs proposed a return on common equity of 9.6% and recovery of but no return on Welsh Plant, Unit 2. The ALJs rejected SWEPCo’s proposed transmission cost recovery mechanism. The estimated potential write-off associated with the ALJs proposal is approximately $22 million which includes $9 million associated with the lack of a return on Welsh Plant, Unit 2. If any of these costs are not recoverable, including environmental investments and 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 33% ) 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. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate the suspension or cancellation of the Turk Plant during its construction period. The testimony also identified five individual items totaling approximately $51 million for potential disallowance relating to Louisiana’s jurisdictional share of Turk Plant. As a result of SWEPCo’s alleged failure to meet its continuing prudence obligations, the LPSC staff recommends one of the following potential unfavorable scenarios: (a) Even sharing of construction cost overruns between SWEPCo and ratepayers, (b) an imposition of a cost cap similar to Texas or (c) approximately a 1% reduction of the rate on common equity for the Turk Plant. As SWEPCo has included the full value of the Turk Plant in rate base since its in-service date, SWEPCo may be required to refund potential over-collections from January 2013 through the date new rates are implemented. As of September 30, 2017, if the LPSC adopts one of these potential scenarios, and disallows the five individual items, pretax write-offs could range from $50 million to $80 million and refund provisions, including interest, could range from $15 million to $27 million . Future annual revenue reductions could range from $3 million to $4 million . Management will continue to vigorously defend against these claims. If the LPSC orders in favor of one of these scenarios, it could reduce future net income and cash flows and impact financial condition. A hearing at the LPSC is scheduled for December 2017. 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, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes SWEPCo’s Louisiana jurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The net annual increase is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental control investment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. A hearing at the LPSC is scheduled fo

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	9 Months Ended
	Sep. 30, 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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.
AEP Transmission 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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 AEP’s and AEPTCo’s 2016 Annual Reports 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 and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. 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 five uncommitted facilities totaling $445 million . In August 2017, AEP executed a $75 million uncommitted letter of credit facility due in August 2018. As of September 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million , which increased to $140 million in October 2017. 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 $76 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2017 , SWEPCo has collected $71 million through a rider for final mine closure and reclamation costs, of which $76 million is recorded in Asset Retirement Obligations, offset by $5 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of September 30, 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 September 30, 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 September 30, 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 $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7 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 $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 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 September 30, 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 September 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $52 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 September 30, 2017 , AEP’s boat and barge lease guarantee liability was $7 million , of which $1 million was recorded in Other Current Liabilities and $6 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheet. 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 September 30, 2017 , I&M’s accrual for all of these sites is $3 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 2,278 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 U.S. 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 continues to work with Westinghouse in the bankruptcy proceedings 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 and remanding the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Plant, Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. In October 2017, the owners filed a motion to stay their claims until January 2018, to afford time for resolution of AEP’s motion to modify the consent decree. Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. 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 were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. 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. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining 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	9 Months Ended
	Sep. 30, 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 unless indicated otherwise. 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. Based on the impairment analysis performed in the third quarter of 2016, AEP recorded a pretax impairment of $2.3 billion in Asset Impairments and Other Related Charges on the statement of operations. Through the third 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. In addition, AEP recorded a $7 million pretax impairment as Asset Impairments and Other Related Charges on AEP’s statements of income related to the sale of Zimmer Plant. The sale is further discussed in the “Disposition” section of this note. DISPOSITION Zimmer Plant (Generation & Marketing Segment) In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to a nonaffiliated party. The transaction closed in the second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition. The Income before Income Tax Expense and Equity Earnings of Zimmer Plant was immaterial for the three and nine months ended September 30, 2017 and 2016. Tanners Creek Plant (Vertically Integrated Utilities Segment) (Applies to AEP and I&M) In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs) to a nonaffiliated party. I&M paid $92 million and the nonaffiliated party took ownership of the Tanners Creek plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. I&M did not record a gain or loss related to this sale and will address recovery of Tanner’s Creek deferred costs in future rate proceedings. If any of the costs associated with Tanner’s Creek are not recoverable, it could reduce future net income and impact financial condition. Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion , which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $226 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income. ASSETS AND LIABILITIES HELD FOR SALE Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) 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. The Income before Income Tax Expense and Equity Earnings of the four plants was approximately $116 million for the three months ended September 30, 2016 and $42 million (excluding the $226 million pretax gain) and $312 million for the nine months ended September 30, 2017 and 2016 , respectively. December 31, 2016 Assets: Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9

Benefit Plans

Benefit Plans	9 Months Ended
	Sep. 30, 2017
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )
Appalachian Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )
Indiana Michigan Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )
Ohio Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )
Public Service Co Of Oklahoma [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )
Southwestern Electric Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )

Business Segments

Business Segments	9 Months Ended
	Sep. 30, 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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.
AEP Transmission 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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.
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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.
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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.
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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.
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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.
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 AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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 (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, 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. Other activities are insignificant. Operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTO’s in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2017 and 2016 and reportable segment balance sheet information as of September 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.

Derivatives and Hedging

Derivatives and Hedging	9 Months Ended
	Sep. 30, 2017
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 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: September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 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 September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 I&M Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 ) PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 ) During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 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 September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2017 and December 31, 2016. 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, the settlement amount that would be required after considering contractual netting arrangements: September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Appalachian Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 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: September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 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 September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 I&M Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 ) PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 ) During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 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 September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2017 and December 31, 2016. 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, the settlement amount that would be required after considering contractual netting arrangements: September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Indiana Michigan Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 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: September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 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 September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 I&M Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 ) PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 ) During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 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 September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2017 and December 31, 2016. 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, the settlement amount that would be required after considering contractual netting arrangements: September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Ohio Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 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: September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 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 September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 I&M Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 ) PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 ) During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 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 September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2017 and December 31, 2016. 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, the settlement amount that would be required after considering contractual netting arrangements: September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 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: September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 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 September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 I&M Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 ) PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 ) During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 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 September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2017 and December 31, 2016. 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, the settlement amount that would be required after considering contractual netting arrangements: September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —
Southwestern Electric Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 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: September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 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 September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 I&M Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 ) PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. The following table shows the results of hedging gains (losses): Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 ) During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 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 and nine months ended September 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 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 September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 123 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The Registrants had immaterial derivative contracts with collateral triggering events in a net liability position as of September 30, 2017 and December 31, 2016. 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, the settlement amount that would be required after considering contractual netting arrangements: September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — —

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co
AEP Transmission Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co
Appalachian Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co
Indiana Michigan Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co
Ohio Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co
Public Service Co Of Oklahoma [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co
Southwestern Electric Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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: September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 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: September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2 The base cost of fixed income securities was $1 billion and $938 million as of September 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $586 million and $592 million as of September 30, 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 September 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 and nine months ended September 30, 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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 September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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 September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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 September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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 September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs for the Registrants as of September 30, 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) Co

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.
AEP Transmission Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.
Appalachian Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.
Indiana Michigan Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.
Ohio Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.
Public Service Co Of Oklahoma [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.
Southwestern Electric Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 % AEP Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is due to the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to the increase in pretax book income driven by the impairment of certain merchant generation assets in the third quarter of 2016. The increase in the ETR is also due to the prior year reversal of a $56 million unrealized capital loss valuation allowance where AEP effectively settled a 2011 audit issue with the IRS, the prior year reversal of a $66 million capital loss valuation allowance related to the pending sale of certain merchant generation assets and prior year tax return adjustments related to the disposition of AEP’s commercial barging operations. APCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to the recording of favorable federal income tax adjustments and a decrease in pretax book income. OPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis and the recording of federal income tax adjustments. Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016 The increase in the ETR is primarily due to changes in other book/tax differences which are accounted for on a flow-through basis, the recording of federal income tax adjustments and an increase in pretax book income. SWEPCo Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016 The decrease in the ETR is primarily due to a $10 million decrease in Income Tax Expense related to income tax benefits attributable to SWEPCo’s noncontrolling interest in Sabine. 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. State Tax Legislation (Applies to AEP, APCo, I&M and OPCo) Legislation was enacted in the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate increased from 7.75% to 9.5% , effective July 1, 2017. The legislation is not expected to materially impact net income, cash flows or financial condition.

Financing Activities

Financing Activities	9 Months Ended
	Sep. 30, 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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
AEP Transmission 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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2 In October 2017, I&M retired $1 million of Notes Payable related to DCC Fuel. In October 2017, AEP Texas retired $41 million of 5.625% Pollution Control Bonds due in 2017 . As of September 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . As of September 30, 2017 , no subsidiaries have exceeded their debt to capitalization limit. 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 September 30, 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% . As of September 30, 2017 , AEP has not exceeded its debt to capitalization limit. 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 September 30, 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 nine months ended September 30, 2017 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LP, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2017 , Mutual Energy SWEPCo, LP had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the nine months ended September 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LP in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5 September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9

Significant Accounting Matters

Significant Accounting Matters (Policies)	9 Months Ended
	Sep. 30, 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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.
AEP Transmission 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017.
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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 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 and nine months ended September 30, 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 Registrants (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	9 Months Ended
	Sep. 30, 2017
Derivatives and Hedging	Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral 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.” OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Accounting for 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. 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. 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. 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.
Appalachian Power Co [Member]
Derivatives and Hedging	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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Cross-Default Triggers (Applies to AEP, APCo 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 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.”
Indiana Michigan Power Co [Member]
Derivatives and Hedging	Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Cross-Default Triggers (Applies to AEP, APCo 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. 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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the 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.
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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC 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. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. 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. 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.” 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.
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	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 mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral 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.” OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC 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. 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.
Southwestern Electric Power Co [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. 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, LLC 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.” Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral 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.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	9 Months Ended
	Sep. 30, 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. 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and 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	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 Transmission Co [Member]
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
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. 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
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. 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and 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	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.
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. 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
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. 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
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. 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 (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Significant Accounting Matter24

Significant Accounting Matters (Tables)	9 Months Ended
	Sep. 30, 2017
Basic and Diluted EPS Calculations	Three Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ 556.7 $ (764.2 ) Less: Net Income Attributable to Noncontrolling Interests 12.0 1.6 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ 544.7 $ (765.8 ) Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.11 491.7 $ (1.56 ) Weighted Average Dilutive Effect of Stock-Based Awards 1.2 (0.01 ) 0.1 — Weighted Average Number of Diluted Shares Outstanding 493.0 $ 1.10 491.8 $ (1.56 ) Nine Months Ended September 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,527.1 $ 245.3 Less: Net Income Attributable to Noncontrolling Interests 15.2 5.3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,511.9 $ 240.0 Weighted Average Number of Basic Shares Outstanding 491.8 $ 3.07 491.4 $ 0.49 Weighted Average Dilutive Effect of Stock-Based Awards 0.6 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.4 $ 3.07 491.6 $ 0.49
Supplementary Information [Text Block]	Nine Months Ended September 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 613.8 $ 637.0 Income Taxes, Net (6.8 ) 32.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 44.5 65.8 Construction Expenditures Included in Current Liabilities as of September 30, 791.6 604.8 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 0.6 0.3 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.8 —

Comprehensive Income (Tables)

Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2017
Changes in Accumulated Other Comprehensive Income by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) Change in Fair Value Recognized in AOCI (15.8 ) (2.0 ) 0.9 — (16.9 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (0.9 ) — — — (0.9 ) Purchased Electricity for Resale 4.9 — — — 4.9 Interest Expense — 0.4 — — 0.4 Amortization of Prior Service Cost (Credit) — — — (5.0 ) (5.0 ) Amortization of Actuarial (Gains)/Losses — — — 5.4 5.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 4.0 0.4 — 0.4 4.8 Income Tax (Expense) Credit 1.4 0.2 — 0.1 1.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.6 0.2 — 0.3 3.1 Net Current Period Other Comprehensive Income (Loss) (13.2 ) (1.8 ) 0.9 0.3 (13.8 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (39.4 ) 2.7 2.7 — (34.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.6 ) — — — (5.6 ) Purchased Electricity for Resale 26.0 — — — 26.0 Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — — (14.8 ) (14.8 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 20.4 1.2 — 1.2 22.8 Income Tax (Expense) Credit 7.1 0.4 — 0.4 7.9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 13.3 0.8 — 0.8 14.9 Net Current Period Other Comprehensive Income (Loss) (26.1 ) 3.5 2.7 0.8 (19.1 ) Balance in AOCI as of September 30, 2017 $ (49.2 ) $ (12.2 ) $ 11.1 $ (125.1 ) $ (175.4 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 )
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.3 ) (0.4 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.3 ) (0.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) 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 (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) 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 September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (4.0 ) (4.0 ) Amortization of Actuarial (Gains)/Losses — 2.6 2.6 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.4 ) (2.2 ) Income Tax (Expense) Credit (0.3 ) (0.5 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) (0.9 ) (1.4 ) Net Current Period Other Comprehensive Loss (0.5 ) (0.9 ) (1.4 ) Balance in AOCI as of September 30, 2017 $ 2.4 $ (12.2 ) $ (9.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 )
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.3 ) (0.3 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) 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 September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.7 ) (0.7 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2017 $ (11.0 ) $ (4.2 ) $ (15.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 )
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 2.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 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 September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.3 ) Income Tax (Expense) Credit (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of September 30, 2017 $ 2.2 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income by Component	PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2017 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (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 September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 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 September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (1.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.0 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2017 $ 2.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) 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) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 1.7 — 1.7 Amortization of Prior Service Cost (Credit) — (1.5 ) (1.5 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 (0.8 ) 0.9 Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Net Current Period Other Comprehensive Income (Loss) 1.1 (0.5 ) 0.6 Balance in AOCI as of September 30, 2017 $ (6.3 ) $ (2.5 ) $ (8.8 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 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 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 )

Rate Matters (Tables)

Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2017
Regulatory Assets Pending Final Regulatory Approval	AEP September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 209.1 $ 159.9 Storm-Related Costs 97.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 42.6 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 24.3 24.1 Cook Plant Turbine 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Other Regulatory Assets Pending Final Regulatory Approval 25.6 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 510.8 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.
Appalachian Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	APCo September 30, 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 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study. The Virginia SCC staff has requested that the company prepare a depreciation study as of December 31, 2017 and submit that study to the Virginia SCC staff in 2018.
Indiana Michigan Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	I&M September 30, 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 15.1 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 13.0 8.1 Rockport Dry Sorbent Injection System - Indiana 9.4 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.5 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 75.3 $ 64.7
Ohio Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	OPCo September 30, 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 Smart Grid 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 September 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 133.7 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 36.7 20.0 Environmental Control Projects 24.3 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.4 — Total Regulatory Assets Pending Final Regulatory Approval $ 195.6 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of September 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $52 million.
Southwestern Electric Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	SWEPCo September 30, 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 0.5 0.8 Regulatory Assets Currently Not Earning a Return Rate Case Expense - Texas 4.1 1.0 Asset Retirement Obligation - Arkansas, Louisiana 3.6 2.7 Shipe Road Transmission Project - FERC 3.3 3.1 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.4 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 89.3 $ 95.9

Commitments, Guarantees and C27

Commitments, Guarantees and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2017
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7
Appalachian Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7
Indiana Michigan Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7
Ohio Power Co [Member]
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 123.2 October 2017 to September 2018 OPCo 0.6 September 2018
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7
Public Service Co Of Oklahoma [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7
Southwestern Electric Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 42.1 APCo 8.8 I&M 3.4 OPCo 6.0 PSO 3.3 SWEPCo 3.7

Impairment, Disposition and A28

Impairment, Disposition and Assets and Liabilities Held for Sale (Tables)	9 Months Ended
	Sep. 30, 2017
Assets and Liabilities Held for Sale	December 31, 2016 Assets: Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9

Benefit Plans (Tables)

Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2017
Components of Net Periodic Benefit Cost	AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.4 $ 2.8 $ 2.6 Interest Cost 50.7 52.9 14.8 15.3 Expected Return on Plan Assets (71.1 ) (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 7.8 Net Periodic Benefit Cost (Credit) $ 24.7 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 72.3 $ 64.3 $ 8.4 $ 7.7 Interest Cost 152.3 158.7 44.5 45.7 Expected Return on Plan Assets (213.5 ) (210.2 ) (76.0 ) (80.3 ) Amortization of Prior Service Cost (Credit) 0.8 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.1 62.9 27.5 23.5 Net Periodic Benefit Cost (Credit) $ 74.0 $ 77.4 $ (47.4 ) $ (55.2 )
Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost	APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.3 $ 2.1 $ 0.3 $ 0.2 Interest Cost 6.5 6.8 2.6 2.7 Expected Return on Plan Assets (8.9 ) (8.8 ) (4.1 ) (4.3 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.6 1.6 1.4 Net Periodic Benefit Cost (Credit) $ 2.5 $ 2.7 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 19.3 20.4 7.9 8.1 Expected Return on Plan Assets (26.8 ) (26.5 ) (12.3 ) (13.0 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 7.8 8.0 4.7 4.1 Net Periodic Benefit Cost (Credit) $ 7.4 $ 8.1 $ (6.4 ) $ (7.6 )
Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost	I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.3 1.7 1.7 Expected Return on Plan Assets (8.6 ) (8.4 ) (3.1 ) (3.2 ) Amortization of Prior Service Credit — — (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 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 10.5 $ 9.2 $ 1.2 $ 1.1 Interest Cost 18.2 19.0 5.2 5.2 Expected Return on Plan Assets (25.9 ) (25.2 ) (9.2 ) (9.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.0 ) (7.1 ) Amortization of Net Actuarial Loss 7.3 7.4 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 10.2 $ 10.5 $ (6.5 ) $ (7.6 )
Ohio Power Co [Member]
Components of Net Periodic Benefit Cost	OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.8 $ 1.6 $ 0.3 $ 0.2 Interest Cost 4.8 5.1 1.6 1.8 Expected Return on Plan Assets (6.9 ) (6.9 ) (3.0 ) (3.3 ) Amortization of Prior Service Credit — — (1.7 ) (1.7 ) Amortization of Net Actuarial Loss 2.0 2.1 1.1 0.9 Net Periodic Benefit Cost (Credit) $ 1.7 $ 1.9 $ (1.7 ) $ (2.1 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 5.6 $ 4.9 $ 0.7 $ 0.6 Interest Cost 14.5 15.4 5.0 5.3 Expected Return on Plan Assets (20.9 ) (20.8 ) (9.0 ) (9.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 5.9 6.1 3.3 2.8 Net Periodic Benefit Cost (Credit) $ 5.2 $ 5.7 $ (5.2 ) $ (6.2 )
Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost	PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.7 $ 1.5 $ 0.2 $ 0.2 Interest Cost 2.6 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 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.9 $ 4.6 $ 0.5 $ 0.5 Interest Cost 8.0 8.4 2.4 2.4 Expected Return on Plan Assets (11.8 ) (11.6 ) (4.2 ) (4.5 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 3.3 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 4.4 $ 4.9 $ (3.0 ) $ (3.5 )
Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost	SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.1 $ 2.0 $ 0.2 $ 0.2 Interest Cost 3.1 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.0 ) (1.5 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.3 1.2 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.3 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Service Cost $ 6.5 $ 6.1 $ 0.6 $ 0.6 Interest Cost 9.2 9.3 2.7 2.7 Expected Return on Plan Assets (12.6 ) (12.3 ) (4.7 ) (5.0 ) Amortization of Prior Service Cost (Credit) — 0.2 (3.9 ) (3.9 ) Amortization of Net Actuarial Loss 3.7 3.6 1.7 1.5 Net Periodic Benefit Cost (Credit) $ 6.8 $ 6.9 $ (3.6 ) $ (4.1 )

Business Segments (Tables)

Business Segments (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting Information [Line Items]
Reportable Segment Information	Three Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,453.8 $ 1,149.7 $ 45.1 $ 441.5 $ 14.6 $ — $ 4,104.7 Other Operating Segments 28.4 23.6 133.4 24.0 16.7 (226.1 ) — Total Revenues $ 2,482.2 $ 1,173.3 $ 178.5 $ 465.5 $ 31.3 $ (226.1 ) $ 4,104.7 Income (Loss) from Continuing Operations $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 297.3 $ 144.0 $ 76.5 $ 33.7 $ 5.2 $ — $ 556.7 Three Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.7 $ 69.5 $ (1,369.2 ) $ 36.4 $ — $ (764.2 ) Nine Months Ended September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,819.3 $ 3,242.7 $ 125.8 $ 1,386.8 $ 39.9 $ — $ 11,614.5 Other Operating Segments 73.8 70.5 456.1 80.7 46.8 (727.9 ) — Total Revenues $ 6,893.1 $ 3,313.2 $ 581.9 $ 1,467.5 $ 86.7 $ (727.9 ) $ 11,614.5 Income (Loss) from Continuing Operations $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Loss from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 639.2 $ 374.3 $ 278.3 $ 246.3 $ (11.0 ) $ — $ 1,527.1 Nine Months Ended September 30, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 64.2 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 387.8 $ 209.5 $ (1,248.8 ) $ 61.7 $ — $ 242.8 September 30, 2017 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) Total Property, Plant and Equipment $ 42,722.9 $ 15,695.2 $ 6,394.2 $ 632.9 $ 359.5 $ (366.5 ) (b) $ 65,438.2 Accumulated Depreciation and Amortization 13,042.9 3,766.2 156.6 161.7 180.8 (186.5 ) (b) 17,121.7 Total Property Plant and Equipment - Net $ 29,680.0 $ 11,929.0 $ 6,237.6 $ 471.2 $ 178.7 $ (180.0 ) (b) $ 48,316.5 Total Assets $ 38,136.4 $ 15,765.0 $ 7,631.2 $ 1,904.4 $ 22,339.9 $ (21,812.0 ) (b) (c) $ 63,964.9 Long-term Debt Due Within One Year: Non-Affiliated $ 1,107.2 $ 703.4 $ — $ 0.1 $ 548.6 $ — $ 2,359.3 Long-term Debt: Affiliated 50.0 — — 32.2 — (82.2 ) — Non-Affiliated 10,644.2 4,738.0 2,682.1 (0.3 ) 298.4 — 18,362.4 Total Long-term Debt $ 11,801.4 $ 5,441.4 $ 2,682.1 $ 32.0 $ 847.0 $ (82.2 ) $ 20,721.7 December 31, 2016 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) 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.
AEP Transmission Co [Member]
Segment Reporting Information [Line Items]
Reportable Segment Information	Three Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 35.9 $ — $ — $ 35.9 Sales to AEP Affiliates 131.3 — 0.1 131.4 Total Revenues $ 167.2 $ — $ 0.1 $ 167.3 Interest Income $ — $ 19.5 $ (19.3 ) (a) $ 0.2 Interest Expense 16.9 19.3 (19.3 ) (a) 16.9 Income Tax Expense 30.2 — — 30.2 Equity Earnings in State Transcos — 59.8 (59.8 ) (b) — Net Income $ 59.8 $ 59.9 $ (59.8 ) (b) $ 59.9 Three Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 33.5 $ — $ — $ 33.5 Sales to AEP Affiliates 91.8 — — 91.8 Total Revenues $ 125.3 $ — $ — $ 125.3 Interest Income $ — $ 14.0 $ (13.9 ) (a) $ 0.1 Interest Expense 11.0 13.9 (13.9 ) (a) 11.0 Income Tax Expense 26.4 — — 26.4 Equity Earnings in State Transcos — 52.3 (52.3 ) (b) — Net Income $ 52.3 $ 52.4 $ (52.3 ) (b) $ 52.4 Nine Months Ended September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 99.2 $ — $ — $ 99.2 Sales to AEP Affiliates 450.2 — — 450.2 Total Revenues $ 549.4 $ — $ — $ 549.4 Interest Income $ 0.1 $ 58.0 $ (57.6 ) (a) $ 0.5 Interest Expense 48.6 57.6 (57.6 ) (a) 48.6 Income Tax Expense 114.3 0.2 — 114.5 Equity Earnings in State Transcos — 224.0 (224.0 ) (b) — Net Income $ 224.0 $ 224.3 $ (224.0 ) (b) $ 224.3 Nine Months Ended September 30, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Revenues from: External Customers $ 89.6 $ — $ — $ 89.6 Sales to AEP Affiliates 268.4 — — 268.4 Total Revenues $ 358.0 $ — $ — $ 358.0 Interest Income $ — $ 41.8 $ (41.6 ) (a) $ 0.2 Interest Expense 32.3 41.6 (41.6 ) (a) 32.3 Income Tax Expense 73.9 — — 73.9 Equity Earnings in State Transcos — 153.0 (153.0 ) (b) — Net Income $ 153.0 $ 153.0 $ (153.0 ) (b) $ 153.0 September 30, 2017 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 6,067.5 $ — $ — $ 6,067.5 Accumulated Depreciation and Amortization 151.5 — — 151.5 Total Transmission Property – Net $ 5,916.0 $ — $ — $ 5,916.0 Notes Receivable - Affiliated $ — $ 2,500.0 $ (2,500.0 ) (c) $ — Total Assets $ 6,455.2 $ 5,010.8 $ (4,917.1 ) (d) $ 6,548.9 Total Long-term Debt $ 2,475.6 $ 2,574.4 $ (2,500.0 ) (c) $ 2,550.0 December 31, 2016 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	9 Months Ended
	Sep. 30, 2017
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments September 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 277.4 $ 8.1 $ 4.2 $ 289.7 $ (143.6 ) $ 146.1 Long-term Risk Management Assets 348.1 3.8 — 351.9 (41.5 ) 310.4 Total Assets 625.5 11.9 4.2 641.6 (185.1 ) 456.5 Current Risk Management Liabilities 202.2 13.5 1.4 217.1 (147.7 ) 69.4 Long-term Risk Management Liabilities 329.6 74.0 — 403.6 (50.9 ) 352.7 Total Liabilities 531.8 87.5 1.4 620.7 (198.6 ) 422.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 93.7 $ (75.6 ) $ 2.8 $ 20.9 $ 13.5 $ 34.4 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a) (in millions) Current Risk Management Assets $ 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 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.1 $ (1.1 ) $ (0.1 ) $ 3.0 Gain (Loss) on Fair Value Portion of Long-term Debt (0.1 ) 1.1 0.1 (3.0 )
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.3 $ 4.2 $ 11.2 $ — Hedging Liabilities (a) 79.9 — 46.7 — AOCI Gain (Loss) Net of Tax (49.2 ) (12.2 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (3.6 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Liabilities Subject to Cross Default Provisions	September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 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 September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	APCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 50.4 $ (20.1 ) $ 30.3 Long-term Risk Management Assets 4.9 (4.3 ) 0.6 Total Assets 55.3 (24.4 ) 30.9 Current Risk Management Liabilities 20.7 (19.8 ) 0.9 Long-term Risk Management Liabilities 4.8 (4.5 ) 0.3 Total Liabilities 25.5 (24.3 ) 1.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 29.8 $ (0.1 ) $ 29.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (1.4 ) (7.4 ) (1.4 )
Liabilities Subject to Cross Default Provisions	September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 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 September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	(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 September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 27.4 $ (15.8 ) $ 11.6 Long-term Risk Management Assets 3.3 (2.8 ) 0.5 Total Assets 30.7 (18.6 ) 12.1 Current Risk Management Liabilities 17.6 (15.6 ) 2.0 Long-term Risk Management Liabilities 3.0 (2.8 ) 0.2 Total Liabilities 20.6 (18.4 ) 2.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 10.1 $ (0.2 ) $ 9.9 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (1.4 ) (7.4 ) (1.4 )
Liabilities Subject to Cross Default Provisions	September 30, 2017 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.9 $ 2.5 $ 274.4 APCo — — — I&M — — — December 31, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 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 September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	OPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.3 $ (0.1 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.3 (0.1 ) 0.2 Current Risk Management Liabilities 7.6 — 7.6 Long-term Risk Management Liabilities 130.9 — 130.9 Total Liabilities 138.5 — 138.5 Total MTM Derivative Contract Net Liabilities $ (138.2 ) $ (0.1 ) $ (138.3 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (1.4 ) (7.4 ) (1.4 )
Public Service Co Of Oklahoma [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	PSO Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 4.7 $ — $ 4.7 Long-term Risk Management Assets — — — Total Assets 4.7 — 4.7 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets $ 4.7 $ — $ 4.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (1.4 ) (7.4 ) (1.4 )
Southwestern Electric Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 406.0 73.7 45.8 10.6 13.7 34.5 Coal Tons 0.5 — 0.2 — — 0.3 Natural Gas MMBtus 48.1 2.0 1.2 — — 18.3 Heating Oil and Gasoline Gallons 7.9 1.5 0.7 1.8 0.8 0.9 Interest Rate USD $ 53.2 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — 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 USD $ 500.0 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2017 December 31, 2016 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 3.5 $ 17.0 $ 7.9 $ 7.6 APCo 0.4 0.3 0.5 0.7 I&M 0.3 0.1 0.3 0.4 OPCo 0.1 — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 —
Fair Value of Derivative Instruments	SWEPCo Fair Value of Derivative Instruments September 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.7 $ (0.2 ) $ 12.5 Long-term Risk Management Assets 0.7 — 0.7 Total Assets 13.4 (0.2 ) 13.2 Current Risk Management Liabilities 0.3 (0.2 ) 0.1 Long-term Risk Management Liabilities — — — Total Liabilities 0.3 (0.2 ) 0.1 Total MTM Derivative Contract Net Assets $ 13.1 $ — $ 13.1 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 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 September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.9 $ — $ — $ — $ — $ — Generation & Marketing Revenues 17.7 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 0.6 — — (0.1 ) Purchased Electricity for Resale 1.0 0.3 0.2 — — — Other Operation 0.1 — — 0.1 — — Maintenance 0.1 0.1 — 0.1 — — Regulatory Assets (a) (8.8 ) 0.1 (0.8 ) (8.7 ) — 0.3 Regulatory Liabilities (a) 15.6 3.7 2.1 — 2.6 7.0 Total Gain (Loss) on Risk Management Contracts $ 26.6 $ 4.5 $ 2.1 $ (8.5 ) $ 2.6 $ 7.2 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation (0.4 ) — — (0.1 ) — — Maintenance (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 7.0 $ — $ — $ — $ — $ — Generation & Marketing Revenues 38.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.6 6.3 — — — Purchased Electricity for Resale 4.9 1.6 0.5 — — — Other Operation 0.5 — — 0.1 — — Maintenance 0.4 0.1 — 0.1 — — Regulatory Assets (a) (26.8 ) — (1.0 ) (25.9 ) — 0.1 Regulatory Liabilities (a) 81.8 28.2 15.3 — 13.7 22.0 Total Gain (Loss) on Risk Management Contracts $ 106.3 $ 30.5 $ 21.1 $ (25.7 ) $ 13.7 $ 22.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.4 $ 0.7 $ 2.9 $ 0.7 I&M (11.0 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.2 1.1 3.0 1.1 PSO 2.8 0.8 3.4 0.8 SWEPCo (6.3 ) (1.4 ) (7.4 ) (1.4 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Book Values and Fair Values of Long-term Debt	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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	September 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 172.9 $ — $ — $ 172.9 Fixed Income Securities – Mutual Funds (b) 103.9 — (0.7 ) 103.2 Equity Securities – Mutual Funds 16.8 17.8 — 34.6 Total Other Temporary Investments $ 293.6 $ 17.8 $ (0.7 ) $ 310.7 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses 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 September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 12.6 0.6 13.6 1.6 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — —
Nuclear Trust Fund Investments	September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3
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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 343.9 $ 343.9 Other Temporary Investments Restricted Cash (a) 158.6 1.4 — 12.9 172.9 Fixed Income Securities – Mutual Funds 103.2 — — — 103.2 Equity Securities – Mutual Funds (b) 34.6 — — — 34.6 Total Other Temporary Investments 296.4 1.4 — 12.9 310.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.2 307.9 300.3 (161.4 ) 448.0 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.3 (6.1 ) 4.3 Interest Rate/Foreign Currency Hedges — 4.2 — — 4.2 Total Risk Management Assets 1.2 321.2 301.6 (167.5 ) 456.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities – Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,680.8 $ 1,365.9 $ 301.6 $ 195.8 $ 3,544.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 3.2 $ 306.6 $ 205.9 $ (174.9 ) $ 340.8 Cash Flow Hedges: Commodity Hedges (c) — 35.3 50.7 (6.1 ) 79.9 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 3.2 $ 343.3 $ 256.6 $ (181.0 ) $ 422.1 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
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable.
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. (c) Represents market prices in dollars per MMBtu. Significant Unobservable Inputs September 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 233.8 $ 252.6 Discounted Cash Flow Forward Market Price (a) $ (0.05 ) $ 92.77 $ 35.82 Counterparty Credit Risk (b) 10 539 204 Natural Gas Contracts 0.9 — Discounted Cash Flow Forward Market Price (c) 2.47 3.03 2.68 FTRs 66.9 4.0 Discounted Cash Flow Forward Market Price (a) (9.80 ) 9.37 0.32 Total $ 301.6 $ 256.6 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
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)
AEP Transmission Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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.
Appalachian Power Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 8.3 $ — $ — $ 0.1 $ 8.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 22.2 30.0 (21.3 ) 30.9 Total Assets $ 8.3 $ 22.2 $ 30.0 $ (21.2 ) $ 39.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.8 $ 0.6 $ (21.2 ) $ 1.2 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.0 $ 0.4 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 29.0 0.2 Discounted Cash Flow Forward Market Price 0.08 6.36 1.20 Total $ 30.0 $ 0.6 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 (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents market prices in dollars per MMBtu.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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	September 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 20.5 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 974.3 32.6 (1.9 ) 785.4 27.1 (5.5 ) Corporate Debt 60.0 3.5 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 9.0 1.0 (0.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,043.3 37.1 (3.3 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,369.2 783.1 (75.4 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,433.0 $ 820.2 $ (78.7 ) $ 2,256.2 $ 707.7 $ (87.2 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 519.5 $ 650.0 $ 1,808.6 $ 2,427.0 Purchases of Investments 525.0 656.5 1,842.2 2,452.9 Gross Realized Gains on Investment Sales 9.8 13.9 198.1 41.9 Gross Realized Losses on Investment Sales 5.2 6.5 145.4 22.2
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 403.6 After 1 year through 5 years 287.9 After 5 years through 10 years 184.2 After 10 years 167.6 Total $ 1,043.3
Fair Value, Assets and Liabilities Measured on Recurring Basis	I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 16.3 $ 12.4 $ (16.6 ) $ 12.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 14.0 — — 6.5 20.5 Fixed Income Securities: United States Government — 974.3 — — 974.3 Corporate Debt — 60.0 — — 60.0 State and Local Government — 9.0 — — 9.0 Subtotal Fixed Income Securities — 1,043.3 — — 1,043.3 Equity Securities - Domestic (b) 1,369.2 — — — 1,369.2 Total Spent Nuclear Fuel and Decommissioning Trusts 1,383.2 1,043.3 — 6.5 2,433.0 Total Assets $ 1,383.2 $ 1,059.6 $ 12.4 $ (10.1 ) $ 2,445.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 16.4 $ 2.2 $ (16.4 ) $ 2.2 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable.
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. (c) Represents market prices in dollars per MMBtu. Significant Unobservable Inputs September 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.3 Discounted Cash Flow Forward Market Price $ 14.85 $ 45.72 $ 33.99 FTRs 11.8 1.9 Discounted Cash Flow Forward Market Price (0.02 ) 6.36 0.71 Total $ 12.4 $ 2.2 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	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 — (0.1 ) 0.2 Total Assets $ 15.6 $ 0.3 $ — $ (0.1 ) $ 15.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 138.5 $ — $ 138.5 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 138.5 Discounted Cash Flow Forward Market Price (a) $ 22.89 $ 61.48 $ 41.21 Counterparty Credit Risk (b) 10 210 150 Total $ — $ 138.5 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. (c) Represents market prices in dollars per MMBtu.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 4.8 $ (0.1 ) $ 4.7 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 4.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (9.80 ) $ 1.03 $ (0.69 ) 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. (c) Represents market prices in dollars per MMBtu.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,721.7 $ 22,988.8 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 2,550.0 2,720.8 1,932.0 1,984.3 APCo 3,979.3 4,721.3 4,033.9 4,613.2 I&M 2,658.5 2,898.7 2,471.4 2,661.6 OPCo 1,718.9 2,068.9 1,763.9 2,092.5 PSO 1,286.4 1,448.0 1,286.0 1,419.0 SWEPCo 2,441.5 2,620.7 2,679.1 2,814.3 (a) Amounts include 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 September 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 2.2 $ 2.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 13.3 (0.2 ) 13.2 Total Assets $ — $ 0.1 $ 13.3 $ 2.0 $ 15.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.2 $ (0.2 ) $ 0.1 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 September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) 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 periods 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 September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 19.8 6.2 3.8 (0.1 ) 4.0 3.8 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 14.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (24.3 ) — — — — — Settlements (49.2 ) (16.2 ) (8.4 ) 1.2 (6.9 ) (7.6 ) Transfers into Level 3 (d) (e) 5.7 — — — — — Transfers out of Level 3 (e) 0.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (9.3 ) (1.9 ) (0.7 ) (9.1 ) (1.9 ) 4.5 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Settlements (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (d) (e) 13.1 0.1 — — — — Transfers out of Level 3 (e) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 37.4 17.2 4.0 (1.0 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (29.5 ) — — — — — Settlements (49.7 ) (18.9 ) (7.1 ) 5.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 16.1 — — — — — Transfers out of Level 3 (e) (9.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 40.1 29.7 10.5 (23.6 ) 4.7 13.2 Balance as of September 30, 2017 $ 45.0 $ 29.4 $ 10.2 $ (138.5 ) $ 4.7 $ 13.1 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Settlements (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (d) (e) 11.2 — — — — — Transfers out of Level 3 (e) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 (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 liabilities/assets or accounts payable.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Natural Gas Contracts $ 0.9 $ — Discounted Cash Flow Forward Market Price (c) $ 2.47 $ 3.03 $ 2.68 FTRs 12.4 0.2 Discounted Cash Flow Forward Market Price (a) (9.80 ) 1.03 (0.69 ) $ 13.3 $ 0.2 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. (c) Represents market prices in dollars per MMBtu.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2017
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %
AEP Transmission Co [Member]
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %
Appalachian Power Co [Member]
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %
Indiana Michigan Power Co [Member]
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %
Ohio Power Co [Member]
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %
Public Service Co Of Oklahoma [Member]
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %
Southwestern Electric Power Co [Member]
Summary of Effective Tax Rate	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEP 33.0 % 40.4 % 35.3 % (195.6 )% AEPTCo 33.5 % 33.5 % 33.8 % 32.6 % APCo 33.4 % 36.1 % 35.5 % 36.2 % I&M 30.6 % 31.8 % 30.1 % 29.5 % OPCo 36.9 % 31.7 % 35.6 % 33.4 % PSO 37.2 % 37.7 % 37.4 % 36.8 % SWEPCo 21.2 % 28.9 % 25.7 % 26.7 %

Financing Activities (Tables)

Financing Activities (Tables)	9 Months Ended
	Sep. 30, 2017
Long-term Debt	Type of Debt September 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 16,038.6 $ 14,761.0 (b) Pollution Control Bonds 1,612.4 1,725.1 Notes Payable 224.5 326.9 Securitization Bonds 1,449.4 1,705.0 Spent Nuclear Fuel Obligation (a) 267.9 266.3 Other Long-term Debt 1,128.9 1,606.9 Total Long-term Debt Outstanding 20,721.7 20,391.2 (b) Long-term Debt Due Within One Year 2,359.3 3,013.4 (b) Long-term Debt $ 18,362.4 $ 17,377.8 (b) (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 $311 million and $311 million as of September 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2
Short Term Debt	September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 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 Nine Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.33 % 0.73 % 1.17 % 0.65 % Net Uncollectible Accounts Receivable Written Off $ 7.0 $ 7.7 $ 18.2 $ 17.5
Customer Accounts Receivable Managed Portfolio	September 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 939.8 $ 945.0 Short-term – Securitized Debt of Receivables 750.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.8 27.7 Unbilled Receivables Related to Securitization 264.2 322.1
AEP Transmission Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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.
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Direct Borrowing Activity	Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP September 30, 2017 September 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 151.9 $ 1.1 $ 38.9 $ 0.9 $ 96.1 $ 75.0 (a) (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 %
Maximum Minimum and Average Interest Rates for Funds Borrowed from and Loaned to AEP	Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Nine Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned September 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.49 % 0.92 % 1.49 % 0.92 % 1.27 % 1.31 % 2016 0.91 % 0.69 % 0.91 % 0.69 % 0.80 % 0.81 %
Appalachian Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
Indiana Michigan Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9
Southwestern Electric Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) AEPTCo Senior Unsecured Notes $ 125.0 3.10 2026 AEPTCo Senior Unsecured Notes 500.0 3.75 2047 APCo Senior Unsecured Notes 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: AEP Texas Pollution Control Bonds 60.0 1.75 2020 AEP Texas Senior Unsecured Notes 400.0 2.40 2022 AEP Texas Senior Unsecured Notes 300.0 3.80 2047 KPCo Pollution Control Bonds 65.0 2.00 2020 KPCo Senior Unsecured Notes 65.0 3.13 2024 KPCo Senior Unsecured Notes 40.0 3.35 2027 KPCo Senior Unsecured Notes 165.0 3.45 2029 KPCo Senior Unsecured Notes 55.0 4.12 2047 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 2,771.1 (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 Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 23.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 4.9 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 22.3 Variable 2019 I&M Notes Payable 23.6 Variable 2019 I&M Notes Payable 23.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 24.3 Variable 2021 I&M Other Long-term Debt 1.1 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 16.2 0.958 2017 OPCo Securitization Bonds 22.5 0.958 2018 OPCo Securitization Bonds 7.6 2.049 2019 OPCo Other Long-term Debt 0.1 1.149 2028 PSO Other Long-term Debt 0.3 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.2 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 KPCo Senior Unsecured Notes 325.0 6.00 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 161.2 5.17 2018 TCC Pollution Control Bonds 60.0 5.20 2030 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 2,427.2
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2017 Limit (in millions) AEPTCo $ 467.2 $ 194.8 $ 235.7 $ 19.3 $ 162.9 $ 795.0 (a) APCo 231.5 160.7 152.2 32.2 (45.9 ) 600.0 I&M 367.4 12.6 205.7 12.6 (164.9 ) 500.0 OPCo 280.6 56.2 141.0 27.9 (167.6 ) 400.0 PSO 185.2 — 121.3 — (118.0 ) 300.0 SWEPCo 187.5 178.6 109.6 169.5 (48.3 ) 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
Nonutility Money Pool Activity	Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2017 2016 Maximum Interest Rate 1.49 % 0.91 % 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 Nine Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 AEPTCo 1.36 % 0.82 % 1.04 % 0.74 % APCo 1.24 % 0.78 % 1.28 % 0.79 % I&M 1.24 % 0.73 % 1.27 % 0.78 % OPCo 1.40 % 0.85 % 0.98 % 0.74 % PSO 1.30 % 0.76 % — % 0.81 % SWEPCo 1.26 % 0.79 % 0.98 % 0.91 %
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool	Maximum Minimum Average Interest Rate Interest Rate Interest Rate Nine Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility September 30, Money Pool Money Pool Money Pool 2017 1.49 % — % 1.27 % 2016 0.91 % 0.69 % 0.79 %
Short Term Debt	September 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 750.0 1.17 % $ 673.0 0.70 % AEP Commercial Paper 295.0 1.39 % 1,040.0 1.02 % SWEPCo Notes Payable 14.3 2.88 % — — % Total Short-term Debt $ 1,059.3 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2017 December 31, 2016 (in millions) APCo $ 116.9 $ 142.0 I&M 132.7 136.7 OPCo 356.3 388.3 PSO 143.4 110.4 SWEPCo 167.1 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.5 $ 1.6 $ 4.2 $ 5.4 I&M 1.8 2.0 4.9 5.6 OPCo 6.1 8.1 16.5 23.4 PSO 2.0 1.8 5.2 4.7 SWEPCo 2.0 2.1 5.4 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2017 2016 2017 2016 (in millions) APCo $ 335.5 $ 361.7 $ 1,029.4 $ 1,071.6 I&M 409.9 448.0 1,218.9 1,220.2 OPCo 616.3 750.9 1,741.7 2,011.2 PSO 407.0 390.6 1,022.6 971.9 SWEPCo 455.0 460.4 1,200.8 1,183.9

Significant Accounting Matter35

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	$ 556.7	$ (764.2)	$ 1,527.1	$ 245.3
Net Income Attributable to Noncontrolling Interests	12	1.6	15.2	5.3
Income (Loss) from Continuing Operations Attributable to Parent	$ 544.7	$ (765.8)	$ 1,511.9	$ 240
Weighted Average Number of Basic AEP Common Shares Outstanding	491,840,722	491,697,809	491,781,643	491,422,921
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 1.11	$ (1.56)	$ 3.07	$ 0.49
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding	492,986,307	491,813,858	492,428,586	491,596,861
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 1.10	$ (1.56)	$ 3.07	$ 0.49
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Antidilutive Shares Outstanding			0	0
Income (Loss) from Equity Method Investments Adjustment			$ 6
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			613.8	$ 637
Net Cash Paid (Received) for Income Taxes			(6.8)	32.2
Noncash Investing and Financing Activities:
Noncash Acquisitions Under Capital Leases			44.5	65.8
Construction Expenditures Included in Current Liabilities as of September 30,			791.6	604.8
Construction Expenditures Included in Noncurrent Liabilities as of September 30,			71.8	0
Acquisition Of Nuclear Fuel Included In Current Liabilities as of September 30,			0.6	0.3
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage			2.8	0
AEP Transmission Co [Member]
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			28.6	20
Net Cash Paid (Received) for Income Taxes			(93.4)	(209.8)
Noncash Investing and Financing Activities:
Construction Expenditures Included in Current Liabilities as of September 30,			239	204.8
Appalachian Power Co [Member]
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			107.1	113.2
Net Cash Paid (Received) for Income Taxes			24.4	55.8
Noncash Investing and Financing Activities:
Noncash Acquisitions Under Capital Leases			2.9	2.1
Construction Expenditures Included in Current Liabilities as of September 30,			107.2	66.8
Indiana Michigan Power Co [Member]
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			92	85.6
Net Cash Paid (Received) for Income Taxes			(69.6)	(36)
Noncash Investing and Financing Activities:
Noncash Acquisitions Under Capital Leases			5.9	16.8
Construction Expenditures Included in Current Liabilities as of September 30,			74.5	83.4
Acquisition Of Nuclear Fuel Included In Current Liabilities as of September 30,			0.6	0.3
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage			2.8	0.1
Ohio Power Co [Member]
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			68.1	78.2
Net Cash Paid (Received) for Income Taxes			69.6	178
Noncash Investing and Financing Activities:
Noncash Acquisitions Under Capital Leases			3.6	2.4
Construction Expenditures Included in Current Liabilities as of September 30,			56.8	30
Public Service Co Of Oklahoma [Member]
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			40.9	45
Net Cash Paid (Received) for Income Taxes			(46.6)	(50.3)
Noncash Investing and Financing Activities:
Noncash Acquisitions Under Capital Leases			1	2.2
Construction Expenditures Included in Current Liabilities as of September 30,			15.1	20.2
Southwestern Electric Power Co [Member]
Amounts Attributable to AEP Common Shareholders
Net Income Attributable to Noncontrolling Interests	$ 11	$ 1.1	12.6	3.3
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Income (Loss) from Equity Method Investments Adjustment			6.3
Cash Paid Received for [Abstract]
Cash Paid for Interest, Net of Capitalized Amounts			109.4	107.6
Net Cash Paid (Received) for Income Taxes			(70.5)	(66.6)
Noncash Investing and Financing Activities:
Noncash Acquisitions Under Capital Leases			2.8	5.5
Construction Expenditures Included in Current Liabilities as of September 30,			$ 40.7	$ 54.3
Restricted Stock Units and Performance Share Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares	1,200,000	100,000	600,000	200,000
Dilutive Securities, Effect on Basic Earnings Per Share	$ (0.01)	$ 0	$ 0	$ 0

New Accounting Pronouncements N

New Accounting Pronouncements New Accounting Pronouncements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Net Periodic Benefit Cost (Credit) Less Service Cost	$ 66
Capitalized Portion Of Net Periodic Benefit Cost	37.00%

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	$ (161.6)	$ (117.9)	$ (156.3)	$ (127.1)
Change in Fair Value Recognized in AOCI	(16.9)	(26.2)	(34)	(16)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	59.7	45.2	165.7	134
Purchased Electricity for Resale	718.1	774	2,156.9	2,134.6
Interest Expense	223.3	225.3	668	667.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	4.8	(2.8)	22.8	(4.2)
Income Tax (Expense) Credit	(264)	534.5	(797.8)	134
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	3.1	(1.7)	14.9	(2.7)
Net Current Period Other Comprehensive Income	(13.8)	(27.9)	(19.1)	(18.7)
Ending Balance in AOCI	(175.4)	(145.8)	(175.4)	(145.8)
Securities Available for Sale [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	10.2	8.3	8.4	7.1
Change in Fair Value Recognized in AOCI	0.9	0.5	2.7	1.7
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0	0
Net Current Period Other Comprehensive Income	0.9	0.5	2.7	1.7
Ending Balance in AOCI	11.1	8.8	11.1	8.8
Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(125.4)	(111.6)	(125.9)	(111.8)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.4	0.2	1.2	0.6
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.2	0.8	0.4
Net Current Period Other Comprehensive Income	0.3	0.2	0.8	0.4
Ending Balance in AOCI	(125.1)	(111.4)	(125.1)	(111.4)
Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(36)	1.9	(23.1)	(5.2)
Change in Fair Value Recognized in AOCI	(15.8)	(26.7)	(39.4)	(17.7)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	4	(3.6)	20.4	(6.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2.6	(2.3)	13.3	(4.2)
Net Current Period Other Comprehensive Income	(13.2)	(29)	(26.1)	(21.9)
Ending Balance in AOCI	(49.2)	(27.1)	(49.2)	(27.1)
Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(10.4)	(16.5)	(15.7)	(17.2)
Change in Fair Value Recognized in AOCI	(2)	0	2.7	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.4	0.6	1.2	1.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.2	0.4	0.8	1.1
Net Current Period Other Comprehensive Income	(1.8)	0.4	3.5	1.1
Ending Balance in AOCI	(12.2)	(16.1)	(12.2)	(16.1)
Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	(0.9)	(5.4)	(5.6)	(20.7)
Purchased Electricity for Resale	4.9	1.8	26	14.2
Interest Expense	0.4	0.6	1.2	1.7
Prior Service Cost (Credit)	(5)	(4.8)	(14.8)	(14.6)
Actuarial (Gains)/Losses	5.4	5	16	15.2
Income Tax (Expense) Credit	1.7	(1.1)	7.9	(1.5)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0	0	0	0
Purchased Electricity for Resale	0	0	0	0
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0	0	0	0
Purchased Electricity for Resale	0	0	0	0
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	(5)	(4.8)	(14.8)	(14.6)
Actuarial (Gains)/Losses	5.4	5	16	15.2
Income Tax (Expense) Credit	0.1	0	0.4	0.2
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	(0.9)	(5.4)	(5.6)	(20.7)
Purchased Electricity for Resale	4.9	1.8	26	14.2
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	1.4	(1.3)	7.1	(2.3)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0	0	0	0
Purchased Electricity for Resale	0	0	0	0
Interest Expense	0.4	0.6	1.2	1.7
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0.2	0.2	0.4	0.6
AEP Transmission Co [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	16.9	11	48.6	32.3
Income Tax (Expense) Credit	(30.2)	(26.4)	(114.5)	(73.9)
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(9.4)	(3.9)	(8.4)	(2.8)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	3	2.8	11.8	9.4
Purchased Electricity for Resale	61.1	69.2	217.1	240.9
Interest Expense	47.2	46.4	143.5	140.7
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.7)	(0.7)	(2.2)	(2.4)
Income Tax (Expense) Credit	(43.2)	(58.7)	(136.7)	(172.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.4)	(0.5)	(1.4)	(1.6)
Net Current Period Other Comprehensive Income	(0.4)	(0.5)	(1.4)	(1.6)
Ending Balance in AOCI	(9.8)	(4.4)	(9.8)	(4.4)
Appalachian Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(11.9)	(7.1)	(11.3)	(6.4)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.5)	(0.5)	(1.4)	(1.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	(0.3)	(0.9)	(1)
Net Current Period Other Comprehensive Income	(0.3)	(0.3)	(0.9)	(1)
Ending Balance in AOCI	(12.2)	(7.4)	(12.2)	(7.4)
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	2.5	3.2	2.9	3.6
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.2)	(0.2)	(0.8)	(0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.1)	(0.2)	(0.5)	(0.6)
Net Current Period Other Comprehensive Income	(0.1)	(0.2)	(0.5)	(0.6)
Ending Balance in AOCI	2.4	3	2.4	3
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.2)	(0.2)	(0.8)	(0.8)
Prior Service Cost (Credit)	(1.4)	(1.2)	(4)	(3.8)
Actuarial (Gains)/Losses	0.9	0.7	2.6	2.2
Income Tax (Expense) Credit	(0.3)	(0.2)	(0.8)	(0.8)
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	0	0
Prior Service Cost (Credit)	(1.4)	(1.2)	(4)	(3.8)
Actuarial (Gains)/Losses	0.9	0.7	2.6	2.2
Income Tax (Expense) Credit	(0.2)	(0.2)	(0.5)	(0.6)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.2)	(0.2)	(0.8)	(0.8)
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	(0.1)	0	(0.3)	(0.2)
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(15.5)	(16)	(16.2)	(16.7)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	3.6	3.4	9.9	13.2
Purchased Electricity for Resale	32.9	43.7	101.2	134.3
Interest Expense	27.5	26.7	83	76.3
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.5	1.5	1.5
Income Tax (Expense) Credit	(28.6)	(35.1)	(61.8)	(84.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.3	1	1
Net Current Period Other Comprehensive Income	0.3	0.3	1	1
Ending Balance in AOCI	(15.2)	(15.7)	(15.2)	(15.7)
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)	(4.2)	(3.4)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0	0
Net Current Period Other Comprehensive Income	0	0	0	0
Ending Balance in AOCI	(4.2)	(3.4)	(4.2)	(3.4)
Indiana Michigan Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(11.3)	(12.6)	(12)	(13.3)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.5	1.5	1.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.3	1	1
Net Current Period Other Comprehensive Income	0.3	0.3	1	1
Ending Balance in AOCI	(11)	(12.3)	(11)	(12.3)
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	1.5	1.5
Prior Service Cost (Credit)	(0.3)	(0.2)	(0.7)	(0.6)
Actuarial (Gains)/Losses	0.3	0.2	0.7	0.6
Income Tax (Expense) Credit	0.2	0.2	0.5	0.5
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	0	0
Prior Service Cost (Credit)	(0.3)	(0.2)	(0.7)	(0.6)
Actuarial (Gains)/Losses	0.3	0.2	0.7	0.6
Income Tax (Expense) Credit	0	0	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.5	0.5	1.5	1.5
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0.2	0.2	0.5	0.5
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]
Other Revenues	1.4	1.4	4.8	4.8
Purchased Electricity for Resale	180.7	203.4	525.4	516.1
Interest Expense	25.7	27.2	76.8	87.7
Income Tax (Expense) Credit	(48.3)	(46.4)	(128)	(122.5)
Net Current Period Other Comprehensive Income			(0.8)	(1)
Ending Balance in AOCI	2.2		2.2
Ohio Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	2.5	3.5	3	4.3
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.5)	(0.3)	(1.3)	(1.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	(0.2)	(0.8)	(1)
Net Current Period Other Comprehensive Income	(0.3)	(0.2)	(0.8)	(1)
Ending Balance in AOCI	2.2	3.3	2.2	3.3
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.5)	(0.3)	(1.3)	(1.4)
Income Tax (Expense) Credit	(0.2)	(0.1)	(0.5)	(0.4)
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]
Other Revenues	1.1	0.7	3.3	2.9
Purchased Electricity for Resale	127.8	130.8	379.8	315.3
Interest Expense	13.2	14.9	40.2	44.6
Income Tax (Expense) Credit	(27.4)	(32)	(42.6)	(56.6)
Net Current Period Other Comprehensive Income			(0.6)	(0.6)
Ending Balance in AOCI	2.8		2.8
Public Service Co Of Oklahoma [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3	3.8	3.4	4.2
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4)	(0.3)	(1)	(0.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.2)	(0.2)	(0.6)	(0.6)
Net Current Period Other Comprehensive Income	(0.2)	(0.2)	(0.6)	(0.6)
Ending Balance in AOCI	2.8	3.6	2.8	3.6
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.4)	(0.3)	(1)	(0.9)
Income Tax (Expense) Credit	(0.2)	(0.1)	(0.4)	(0.3)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(9)	(8.9)	(9.4)	(9.4)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0.4	0.6	1.4	1.6
Purchased Electricity for Resale	40	35.9	118.7	97.5
Interest Expense	31.9	32.6	92.7	92
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.3	0.5	0.9	1.2
Income Tax (Expense) Credit	(22.5)	(33.2)	(45.2)	(53.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.2	0.3	0.6	0.8
Net Current Period Other Comprehensive Income	0.2	0.3	0.6	0.8
Ending Balance in AOCI	(8.8)	(8.6)	(8.8)	(8.6)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(2.3)	(0.7)	(2)	(0.3)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.3)	(0.2)	(0.8)	(0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.2)	(0.1)	(0.5)	(0.5)
Net Current Period Other Comprehensive Income	(0.2)	(0.1)	(0.5)	(0.5)
Ending Balance in AOCI	(2.5)	(0.8)	(2.5)	(0.8)
Southwestern Electric Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(6.7)	(8.2)	(7.4)	(9.1)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.6	0.7	1.7	2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.4	0.4	1.1	1.3
Net Current Period Other Comprehensive Income	0.4	0.4	1.1	1.3
Ending Balance in AOCI	(6.3)	(7.8)	(6.3)	(7.8)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.6	0.7	1.7	2
Prior Service Cost (Credit)	(0.5)	(0.4)	(1.5)	(1.4)
Actuarial (Gains)/Losses	0.2	0.2	0.7	0.6
Income Tax (Expense) Credit	0.1	0.2	0.3	0.4
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	0	0
Prior Service Cost (Credit)	(0.5)	(0.4)	(1.5)	(1.4)
Actuarial (Gains)/Losses	0.2	0.2	0.7	0.6
Income Tax (Expense) Credit	(0.1)	(0.1)	(0.3)	(0.3)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.6	0.7	1.7	2
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	$ 0.2	$ 0.3	$ 0.6	$ 0.7

Rate Matters - Regulatory Asset

Rate Matters - Regulatory Assets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 5,640		$ 5,625.5
Accumulated Depreciation and Amortization	17,121.7		16,397.3
AEP Transmission Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	138		112.3
Accumulated Depreciation and Amortization	151.5		99.6
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,100.1		1,121.1
Accumulated Depreciation and Amortization	3,836.7		3,636.8
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	941		916.6
Accumulated Depreciation and Amortization	3,022.5		3,005.1
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,014.7		1,107.5
Accumulated Depreciation and Amortization	2,182.8		2,116
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	393.6		340.2
Accumulated Depreciation and Amortization	1,382.8		1,272.7
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	566.4		551.2
Accumulated Depreciation and Amortization	2,670.5		2,567.1
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	510.8		450.1
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	46.9		39.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	75.3		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	195.6		118.1
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	89.3		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	3.6		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	15.1		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	15.1		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]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	13		8.1
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	13		8.1
Environmental Control 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	24.3		24.1
Environmental Control 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	24.3		13.1
Environmental Control 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	0		11
Smart Grid 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	1.1		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	0.5		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	25.6		21.2
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.6		0.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1.5		0.9
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.4		0
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	2.4		1.9
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	37.2		29.6
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	37.2		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	209.1		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	133.7		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	4.1		1
Rockport Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	9.4		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	97.4		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	42.6		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	36.7		$ 20
Northeastern Plant, Unit 3 [Member] | Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	52	$ 41
Northeastern Plant, Unit 3 [Member] | Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 52	$ 41

Rate Matters - East Companies

Rate Matters - East Companies (Details) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 26, 2017USD ($)	Sep. 30, 2017USD ($)MW	Dec. 31, 2016USD ($)
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 3,710	$ 3,183.9
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		493.5	390.3
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		478.9	654.2
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 350.7	$ 221.5
FERC Transmission Complaint - AEP PJM Participants [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity		8.32%
Approved Return on Common Equity		10.99%
Kentucky Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 66
Requested Return on Common Equity		10.31%
Requested Annual Increase in Environmental Surcharge		$ 4
Adjusted Requested Annual Increase		60
KPCo's Regulatory Asset Related to the Retired Big Sandy, Unit 2		289
Indiana Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 263
Requested Return on Common Equity		10.60%
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider		$ 23
Amount of Increase Related to Annual Depreciation Rates		78
Amount of Increase Related to Amortization of Regulatory Assets		11
Indiana Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 263
Requested Return on Common Equity		10.60%
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider		$ 23
Amount of Increase Related to Annual Depreciation Rates		78
Amount of Increase Related to Amortization of Regulatory Assets		11
Michigan Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 52
Requested Return on Common Equity		10.60%
Amount of Increase Related to Annual Depreciation Rates		$ 23
Amount of Increase Related to Amortization of Regulatory Assets		4
Michigan Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 52
Requested Return on Common Equity		10.60%
Amount of Increase Related to Annual Depreciation Rates		$ 23
Amount of Increase Related to Amortization of Regulatory Assets		$ 4
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 | MW		400
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW		500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement		100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement		50.00%
Return on Common Equity Proposed in the Amended ESP Filing		10.41%
Return on Common Equity Filed in the Pending Stipulation Agreement		10.00%
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
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 | MW		400
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW		500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement		100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement		50.00%
Return on Common Equity Proposed in the Amended ESP Filing		10.41%
Return on Common Equity Filed in the Pending Stipulation Agreement		10.00%
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		$ 274
Construction Work in Progress		17
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		274
Construction Work in Progress		17
2016 SEET Filing [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		58
2016 SEET Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Provision for Refund		58
Subsequent Event [Member] | Kentucky Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Proposed Lease Expense to be Deferred with a WACC Carrying Charge for Recovery	$ 100
Subsequent Event [Member] | Michigan Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
MPSC Recommended Annual Net Revenue Increase	$ 49
MPSC Recommended Return on Common Equity	9.80%
Subsequent Event [Member] | Michigan Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
MPSC Recommended Annual Net Revenue Increase	$ 49
MPSC Recommended Return on Common Equity	9.80%
Subsequent Event [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.30%
Subsequent Event [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.30%
Minimum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		215
Minimum [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		215
Minimum [Member] | Subsequent Event [Member] | Kentucky Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	8.60%
KPSC Recommended Annual Net Revenue Increase	$ 13
Minimum [Member] | Subsequent Event [Member] | Michigan Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.30%
Minimum [Member] | Subsequent Event [Member] | Michigan Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.30%
Maximum [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		290
Maximum [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Rate Caps Related to the Distribution Investment Rider Range		$ 290
Maximum [Member] | Subsequent Event [Member] | Kentucky Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	8.85%
KPSC Recommended Annual Net Revenue Increase	$ 40
Maximum [Member] | Subsequent Event [Member] | Michigan Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.50%
Maximum [Member] | Subsequent Event [Member] | Michigan Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Return on Common Equity	9.50%

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 26, 2017	Sep. 30, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 3,710	$ 3,183.9
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		114	148.2
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		145.2	$ 113.8
AEP Texas Interim Transmission and Distribution Rates [Member]
Public Utilities, General Disclosures [Line Items]
AEP Texas Cumulative Revenues Subject to Review		697
Hurricane Harvey Storm [Member]
Public Utilities, General Disclosures [Line Items]
Annual Recovery of Storm Costs through Base Rates		1
AEP Texas Total Storm-Related Costs		97
AEP Texas Hurricane Harvey Storm-Related Costs		$ 73
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		$ 709
FERC Transmission Complaint - AEP SPP Participants [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		10.70%
Intervenor Recommended Return on Common Equity		8.36%
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 Return on Common Equity		10.00%
Recommended Investment Disallowance Resulting in Possible Write-Offs		$ 89
Requested Net Increase in Texas Annual Revenues		69
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%
Amount of Write-Off Related to Environmental Controls		$ 40
Amount of Write-Off Related to Welsh Plant Unit 2		25
ALJ Proposed Net Increase in Texas Annual Revenues		$ 50
ALJ Proposed Return on Equity		9.60%
ALJ’s Total Proposed Amount of Write-Off		$ 22
ALJ’s Proposed Amount of Write-Off Related to Welsh Plant Unit 2		$ 9
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Common Equity		10.00%
Recommended Investment Disallowance Resulting in Possible Write-Offs		$ 89
Requested Net Increase in Texas Annual Revenues		69
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%
Amount of Write-Off Related to Environmental Controls		$ 40
Amount of Write-Off Related to Welsh Plant Unit 2		25
ALJ Proposed Net Increase in Texas Annual Revenues		$ 50
ALJ Proposed Return on Equity		9.60%
ALJ’s Total Proposed Amount of Write-Off		$ 22
ALJ’s Proposed Amount of Write-Off Related to Welsh Plant Unit 2		$ 9
Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share Of Turk Plant		33.00%
Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share Of Turk Plant		33.00%
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 2017 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		31
Louisiana 2017 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		31
Oklahoma Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 156
Requested Return on Common Equity		10.00%
Amount of Increase Related to Annual Depreciation Rates		$ 42
Recommended Disallowance for Capitalized Incentives		38
Recommended Potential Refund Related to an SPP Rider		43
Combined Potential Write-off and Refund		163
Oklahoma Base Rate Case - 2017 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 156
Requested Return on Common Equity		10.00%
Amount of Increase Related to Annual Depreciation Rates		$ 42
Recommended Disallowance for Capitalized Incentives		38
Recommended Potential Refund Related to an SPP Rider		43
Combined Potential Write-off and Refund		163
Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		82
Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		82
Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 3 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		346
Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 3 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		346
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		850
Construction Work in Progress		398
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
Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs		131
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
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
Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs		131
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		626
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		$ 626
FERC SWEPCo Power Supply Agreements Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity		11.10%
Intervenor Recommended Return on Common Equity		8.41%
Minimum [Member] | 2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Return on Equity		9.20%
Recommended Net Increase in Texas Annual Revenues		$ 36
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%
Recommended Net Increase in Texas Annual Revenues		$ 36
Minimum [Member] | Oklahoma Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Net Increase in Oklahoma Annual Revenues		$ 28
Recommended Return on Equity		8.00%
Minimum [Member] | Oklahoma Base Rate Case - 2017 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Net Increase in Oklahoma Annual Revenues		$ 28
Recommended Return on Equity		8.00%
Minimum [Member] | Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Investment Disallowance Resulting in Possible Write-Offs		$ 27
Minimum [Member] | Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Investment Disallowance Resulting in Possible Write-Offs		$ 27
Maximum [Member] | 2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Return on Equity		9.35%
Recommended Net Increase in Texas Annual Revenues		$ 47
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%
Recommended Net Increase in Texas Annual Revenues		$ 47
Maximum [Member] | Oklahoma Base Rate Case - 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Net Increase in Oklahoma Annual Revenues		$ 108
Recommended Return on Equity		9.00%
Maximum [Member] | Oklahoma Base Rate Case - 2017 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Net Increase in Oklahoma Annual Revenues		$ 108
Recommended Return on Equity		9.00%
Maximum [Member] | Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Investment Disallowance Resulting in Possible Write-Offs		$ 82
Maximum [Member] | Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Recommended Investment Disallowance Resulting in Possible Write-Offs		$ 82
Subsequent Event [Member] | Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
LPSC Staff Recommendation for Potential Disallowance Related to Turk Plant	$ 51
LPSC Staff Recommended Percentage Reduction of the Return on Common Equity for the Turk Plant	1.00%
Subsequent Event [Member] | Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
LPSC Staff Recommendation for Potential Disallowance Related to Turk Plant	$ 51
LPSC Staff Recommended Percentage Reduction of the Return on Common Equity for the Turk Plant	1.00%
Subsequent Event [Member] | Minimum [Member] | Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
LPSC Staff Recommended Potential Write-Off Range	$ 50
LPSC Staff Recommended Potential Refund Provisions Range	15
LPSC Staff Recommended Future Revenue Reductions Range	3
Subsequent Event [Member] | Minimum [Member] | Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
LPSC Staff Recommended Potential Write-Off Range	50
LPSC Staff Recommended Potential Refund Provisions Range	15
LPSC Staff Recommended Future Revenue Reductions Range	3
Subsequent Event [Member] | Maximum [Member] | Louisiana Turk Plant Prudence Review [Member]
Public Utilities, General Disclosures [Line Items]
LPSC Staff Recommended Potential Write-Off Range	80
LPSC Staff Recommended Potential Refund Provisions Range	27
LPSC Staff Recommended Future Revenue Reductions Range	4
Subsequent Event [Member] | Maximum [Member] | Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
LPSC Staff Recommended Potential Write-Off Range	80
LPSC Staff Recommended Potential Refund Provisions Range	27
LPSC Staff Recommended Future Revenue Reductions Range	$ 4

Commitments, Guarantees and C41

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 26, 2017	Sep. 30, 2017
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		$ 123.2
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported		45
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Letters of Credit Limit		1,200
Uncommitted Facility		445
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		115
Estimated Final Cost Mine Reclamation		76
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		71
Amount Collected, Rider Mine Close Other Assets Noncurrent		5
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		76
Guarantees of Equity Method Investees [Member]
Maximum Potential Amount of Future Payments Associated with Guarantee		75
Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements		42.1
Boat and Barge Leases [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases		52
Guarantee Liability related to AEPRO Boat and Barge Leases		7
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Current Liabilities		1
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Noncurrent Liabilities		6
Appalachian Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements		8.8
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements		3.4
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligations 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		$ 8
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		0.6
Ohio Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements		6
Public Service Co Of Oklahoma [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements		3.3
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		76
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		71
Amount Collected, Rider Mine Close Other Assets Noncurrent		5
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		76
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements		3.7
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligations for Remaining Railcars		$ 9
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		$ 10
Superfund and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		3
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		3
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
August 2018 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Uncommitted Facility		75
July 2019 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Bilateral Letters of Credit, Matured		$ 46
Subsequent Event [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	$ 140

Impairment, Disposition and A42

Impairment, Disposition and Assets and Liabilities Held for Sale (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income	$ 0	$ 0	$ 0	$ (2.5)
Total Assets Classified as Held for Sale on the Balance Sheets					$ 1,951.2
Discontinued Operations and Disposal Groups (Textuals)
Asset Impairments and Other Related Charges	(2.5)	2,264.9	10.6	2,264.9
Indiana Michigan Power Co [Member]
Discontinued Operations and Disposal Groups (Textuals)
Asset Impairments and Other Related Charges	0	10.5	0	10.5
Generation And Marketing [Member]
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income	0	0	0	0
Fuel					145.5
Materials and Supplies					49.4
Property, Plant and Equipment - Net					1,756.2
Other Class of Assets That Are Not Major					0.1
Total Assets Classified as Held for Sale on the Balance Sheets					1,951.2
Long-term Debt					134.8
Waterford Plant Upgrade Liability					52.2
Asset Retirement Obligations					36.7
Other Classes of Liabilities That Are Not Major					12.2
Total Liabilities Classified as Held for Sale on the Balance Sheets					235.9
Discontinued Operations and Disposal Groups (Textuals)
Cash Proceeds from Sale of Plants Gross			2,200
Cash Proceeds from Sale of Disposition Plants, Net			1,200
Pre-tax Gain on Sale of Plants			226
Income from Continuing Operations before Income Tax Expense and Equity Earnings of the Plants Sold		116	42	312
Generation And Marketing [Member] | Merchant Coal-Fired Generation Assets [Member]
Discontinued Operations and Disposal Groups (Textuals)
Asset Impairments and Other Related Charges			4	2,300
Generation And Marketing [Member] | Merchant Coal-Fired Generation Assets [Member] | Wm. H. Zimmer Generating Station [Member]
Discontinued Operations and Disposal Groups (Textuals)
Asset Impairments and Other Related Charges			7
Vertically Integrated Utilities [Member]
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income	$ 0	$ 0	$ 0	0
Total Assets Classified as Held for Sale on the Balance Sheets					$ 0
Tanners Creek Plant Units 1 Through 4 [Member] | Vertically Integrated Utilities [Member]
Discontinued Operations and Disposal Groups (Textuals)
Payment On Sale Of Property Plant And Equipment				$ 92

Benefit Plans (Details)

Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 24.1	$ 21.4	$ 72.3	$ 64.3
Interest Cost	50.7	52.9	152.3	158.7
Expected Return on Plan Assets	(71.1)	(70.1)	(213.5)	(210.2)
Amortization of Prior Service Cost (Credit)	0.3	0.6	0.8	1.7
Amortization of Net Actuarial Loss	20.7	21	62.1	62.9
Net Periodic Benefit Cost (Credit)	24.7	25.8	74	77.4
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.3	2.1	7	6.1
Interest Cost	6.5	6.8	19.3	20.4
Expected Return on Plan Assets	(8.9)	(8.8)	(26.8)	(26.5)
Amortization of Prior Service Cost (Credit)	0	0	0.1	0.1
Amortization of Net Actuarial Loss	2.6	2.6	7.8	8
Net Periodic Benefit Cost (Credit)	2.5	2.7	7.4	8.1
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3.5	3.1	10.5	9.2
Interest Cost	6.1	6.3	18.2	19
Expected Return on Plan Assets	(8.6)	(8.4)	(25.9)	(25.2)
Amortization of Prior Service Cost (Credit)	0	0	0.1	0.1
Amortization of Net Actuarial Loss	2.4	2.5	7.3	7.4
Net Periodic Benefit Cost (Credit)	3.4	3.5	10.2	10.5
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.8	1.6	5.6	4.9
Interest Cost	4.8	5.1	14.5	15.4
Expected Return on Plan Assets	(6.9)	(6.9)	(20.9)	(20.8)
Amortization of Prior Service Cost (Credit)	0	0	0.1	0.1
Amortization of Net Actuarial Loss	2	2.1	5.9	6.1
Net Periodic Benefit Cost (Credit)	1.7	1.9	5.2	5.7
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.7	1.5	4.9	4.6
Interest Cost	2.6	2.8	8	8.4
Expected Return on Plan Assets	(3.9)	(3.9)	(11.8)	(11.6)
Amortization of Prior Service Cost (Credit)	0	0.1	0	0.2
Amortization of Net Actuarial Loss	1.1	1.1	3.3	3.3
Net Periodic Benefit Cost (Credit)	1.5	1.6	4.4	4.9
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.1	2	6.5	6.1
Interest Cost	3.1	3.1	9.2	9.3
Expected Return on Plan Assets	(4.2)	(4)	(12.6)	(12.3)
Amortization of Prior Service Cost (Credit)	0	0	0	0.2
Amortization of Net Actuarial Loss	1.3	1.2	3.7	3.6
Net Periodic Benefit Cost (Credit)	2.3	2.3	6.8	6.9
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.8	2.6	8.4	7.7
Interest Cost	14.8	15.3	44.5	45.7
Expected Return on Plan Assets	(25.3)	(26.8)	(76)	(80.3)
Amortization of Prior Service Cost (Credit)	(17.3)	(17.3)	(51.8)	(51.8)
Amortization of Net Actuarial Loss	9.2	7.8	27.5	23.5
Net Periodic Benefit Cost (Credit)	(15.8)	(18.4)	(47.4)	(55.2)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.2	0.8	0.7
Interest Cost	2.6	2.7	7.9	8.1
Expected Return on Plan Assets	(4.1)	(4.3)	(12.3)	(13)
Amortization of Prior Service Cost (Credit)	(2.5)	(2.5)	(7.5)	(7.5)
Amortization of Net Actuarial Loss	1.6	1.4	4.7	4.1
Net Periodic Benefit Cost (Credit)	(2.1)	(2.5)	(6.4)	(7.6)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.4	0.4	1.2	1.1
Interest Cost	1.7	1.7	5.2	5.2
Expected Return on Plan Assets	(3.1)	(3.2)	(9.2)	(9.6)
Amortization of Prior Service Cost (Credit)	(2.3)	(2.4)	(7)	(7.1)
Amortization of Net Actuarial Loss	1.1	0.9	3.3	2.8
Net Periodic Benefit Cost (Credit)	(2.2)	(2.6)	(6.5)	(7.6)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.3	0.2	0.7	0.6
Interest Cost	1.6	1.8	5	5.3
Expected Return on Plan Assets	(3)	(3.3)	(9)	(9.7)
Amortization of Prior Service Cost (Credit)	(1.7)	(1.7)	(5.2)	(5.2)
Amortization of Net Actuarial Loss	1.1	0.9	3.3	2.8
Net Periodic Benefit Cost (Credit)	(1.7)	(2.1)	(5.2)	(6.2)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.5	0.5
Interest Cost	0.8	0.8	2.4	2.4
Expected Return on Plan Assets	(1.4)	(1.5)	(4.2)	(4.5)
Amortization of Prior Service Cost (Credit)	(1.1)	(1.1)	(3.2)	(3.2)
Amortization of Net Actuarial Loss	0.5	0.4	1.5	1.3
Net Periodic Benefit Cost (Credit)	(1)	(1.2)	(3)	(3.5)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.6	0.6
Interest Cost	0.9	0.9	2.7	2.7
Expected Return on Plan Assets	(1.5)	(1.7)	(4.7)	(5)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.3)	(3.9)	(3.9)
Amortization of Net Actuarial Loss	0.5	0.5	1.7	1.5
Net Periodic Benefit Cost (Credit)	$ (1.2)	$ (1.4)	$ (3.6)	$ (4.1)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Reportable Segment Information
Vertically Integrated Utilities Revenues		$ 2,453.8	$ 2,538.3	$ 6,819.3	$ 6,864.6
Transmission and Distribution Utilities Revenues		1,149.7	1,245.4	3,242.7	3,398.9
Generation & Marketing Revenues		441.5	823.3	1,386.8	2,192.5
Corporate and Other Revenues		59.7	45.2	165.7	134
Sales to AEP Affiliates		0	0	0	0
Total Revenues		4,104.7	4,652.2	11,614.5	12,590
Interest Expense		223.3	225.3	668	667.2
Income Tax Expense		264	(534.5)	797.8	(134)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		556.7	(764.2)	1,527.1	245.3
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	(2.5)
Net Income (Loss)		556.7	(764.2)	1,527.1	242.8
Balance Sheet Information
Total Property, Plant and Equipment		65,438.2		65,438.2		$ 62,036.6
Accumulated Depreciation and Amortization		17,121.7		17,121.7		16,397.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		48,316.5		48,316.5		45,639.3
Assets Held for Sale						1,951.2
Total Assets		63,964.9		63,964.9		63,467.7
Long-term Debt Due Within One Year		2,359.3		2,359.3		2,878
Long-term Debt - Affiliated		0		0		0
Long-term Debt		18,362.4		18,362.4		17,378.4
Total Long-term Debt Outstanding		20,721.7		20,721.7		20,256.4
Liabilities Held for Sale		0		0		235.9
Vertically Integrated Utilities [Member]
Reportable Segment Information
Vertically Integrated Utilities Revenues		2,453.8	2,538.3	6,819.3	6,864.6
Sales to AEP Affiliates		28.4	18	73.8	63.2
Total Revenues		2,482.2	2,556.3	6,893.1	6,927.8
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		297.3	343.4	639.2	832.6
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		297.3	343.4	639.2	832.6
Balance Sheet Information
Total Property, Plant and Equipment		42,722.9		42,722.9		41,552.6
Accumulated Depreciation and Amortization		13,042.9		13,042.9		12,596.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		29,680		29,680		28,955.9
Assets Held for Sale						0
Total Assets		38,136.4		38,136.4		37,428.3
Long-term Debt Due Within One Year		1,107.2		1,107.2		1,519.9
Long-term Debt - Affiliated		50		50		20
Long-term Debt		10,644.2		10,644.2		10,353.3
Total Long-term Debt Outstanding		11,801.4		11,801.4		11,893.2
Liabilities Held for Sale						0
Transmission And Distribution Utilities [Member]
Reportable Segment Information
Transmission and Distribution Utilities Revenues		1,149.7	1,245.4	3,242.7	3,398.9
Sales to AEP Affiliates		23.6	30.2	70.5	69.6
Total Revenues		1,173.3	1,275.6	3,313.2	3,468.5
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		144	155.7	374.3	387.8
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		144	155.7	374.3	387.8
Balance Sheet Information
Total Property, Plant and Equipment		15,695.2		15,695.2		14,762.2
Accumulated Depreciation and Amortization		3,766.2		3,766.2		3,655
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		11,929		11,929		11,107.2
Assets Held for Sale						0
Total Assets		15,765		15,765		14,802.4
Long-term Debt Due Within One Year		703.4		703.4		309.4
Long-term Debt - Affiliated		0		0		0
Long-term Debt		4,738		4,738		4,672.2
Total Long-term Debt Outstanding		5,441.4		5,441.4		4,981.6
Liabilities Held for Sale						0
AEP Transmission Holdco [Member]
Reportable Segment Information
Transmission Revenues		45.1	39.5	125.8	110.1
Sales to AEP Affiliates		133.4	92.9	456.1	272.6
Total Revenues		178.5	132.4	581.9	382.7
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		76.5	69.5	278.3	209.5
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		76.5	69.5	278.3	209.5
Balance Sheet Information
Total Property, Plant and Equipment		6,394.2		6,394.2		5,354
Accumulated Depreciation and Amortization		156.6		156.6		101.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,237.6		6,237.6		5,252.6
Assets Held for Sale						0
Total Assets		7,631.2		7,631.2		6,384.8
Long-term Debt Due Within One Year		0		0		0
Long-term Debt - Affiliated		0		0		0
Long-term Debt		2,682.1		2,682.1		2,055.7
Total Long-term Debt Outstanding		2,682.1		2,682.1		2,055.7
Liabilities Held for Sale						0
Generation And Marketing [Member]
Reportable Segment Information
Generation & Marketing Revenues		441.5	823.3	1,386.8	2,192.5
Sales to AEP Affiliates		24	36.1	80.7	98.7
Total Revenues		465.5	859.4	1,467.5	2,291.2
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		33.7	(1,369.2)	246.3	(1,248.8)
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		33.7	(1,369.2)	246.3	(1,248.8)
Balance Sheet Information
Total Property, Plant and Equipment		632.9		632.9		364.7
Accumulated Depreciation and Amortization		161.7		161.7		42.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		471.2		471.2		322.5
Assets Held for Sale						1,951.2
Total Assets		1,904.4		1,904.4		3,386.1
Long-term Debt Due Within One Year		0.1		0.1		500.1
Long-term Debt - Affiliated		32.2		32.2		32.2
Long-term Debt		(0.3)		(0.3)		0
Total Long-term Debt Outstanding		32		32		532.3
Liabilities Held for Sale						235.9
All Other [Member]
Reportable Segment Information
Corporate and Other Revenues	[1]	14.6	5.7	39.9	23.9
Sales to AEP Affiliates	[1]	16.7	19.1	46.8	55.2
Total Revenues	[1]	31.3	24.8	86.7	79.1
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	[1]	5.2	36.4	(11)	64.2
Income (Loss) from Discontinued Operations, Net of Tax	[1]	0	0	0	(2.5)
Net Income (Loss)	[1]	5.2	36.4	(11)	61.7
Balance Sheet Information
Total Property, Plant and Equipment	[1]	359.5		359.5		356.6
Accumulated Depreciation and Amortization	[1]	180.8		180.8		186
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	178.7		178.7		170.6
Assets Held for Sale						0
Total Assets	[1]	22,339.9		22,339.9		20,354.8
Long-term Debt Due Within One Year	[1]	548.6		548.6		548.6
Long-term Debt - Affiliated	[1]	0		0		0
Long-term Debt	[1]	298.4		298.4		297.2
Total Long-term Debt Outstanding	[1]	847		847		845.8
Liabilities Held for Sale						0
Reconciling Adjustments [Member]
Reportable Segment Information
Corporate and Other Revenues		0	0	0	0
Total Revenues		(226.1)	(196.3)	(727.9)	(559.3)
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		0	0	0	0
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		0	0	0	0
Balance Sheet Information
Total Property, Plant and Equipment	[2]	(366.5)		(366.5)		(353.5)
Accumulated Depreciation and Amortization	[2]	(186.5)		(186.5)		(184)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[2]	(180)		(180)		(169.5)
Assets Held for Sale						0
Total Assets	[2],[3]	(21,812)		(21,812)		(18,888.7)
Long-term Debt Due Within One Year		0		0		0
Long-term Debt - Affiliated		(82.2)		(82.2)		(52.2)
Long-term Debt		0		0		0
Total Long-term Debt Outstanding		(82.2)		(82.2)		(52.2)
Liabilities Held for Sale						0
AEP Transmission Co [Member]
Reportable Segment Information
Transmission Revenues		35.9	33.5	99.2	89.6
Sales to AEP Affiliates		131.4	91.8	450.2	268.4
Total Revenues		167.3	125.3	549.4	358
Interest Income		0.2	0.1	0.5	0.2
Interest Expense		16.9	11	48.6	32.3
Income Tax Expense		30.2	26.4	114.5	73.9
Equity Earnings in State Transcos		0	0	0	0
Net Income (Loss)		59.9	52.4	224.3	153
Balance Sheet Information
Total Property, Plant and Equipment		6,067.5		6,067.5		5,054.2
Accumulated Depreciation and Amortization		151.5		151.5		99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,916		5,916		4,954.6
Notes Receivable, Related Parties		0		0		0
Total Assets		6,548.9		6,548.9		5,349.8
Long-term Debt		2,550		2,550		1,932
Total Long-term Debt Outstanding		2,550		2,550		1,932
AEP Transmission Co [Member] | State Transcos [Member]
Reportable Segment Information
Transmission Revenues		35.9	33.5	99.2	89.6
Sales to AEP Affiliates		131.3	91.8	450.2	268.4
Total Revenues		167.2	125.3	549.4	358
Interest Income		0	0	0.1	0
Interest Expense		16.9	11	48.6	32.3
Income Tax Expense		30.2	26.4	114.3	73.9
Equity Earnings in State Transcos		0	0	0	0
Net Income (Loss)		59.8	52.3	224	153
Balance Sheet Information
Total Property, Plant and Equipment		6,067.5		6,067.5		5,054.2
Accumulated Depreciation and Amortization		151.5		151.5		99.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,916		5,916		4,954.6
Notes Receivable, Related Parties		0		0		0
Total Assets		6,455.2		6,455.2		5,337.5
Total Long-term Debt Outstanding		2,475.6		2,475.6		1,932
AEP Transmission Co [Member] | AEPTCo Parent [Member]
Reportable Segment Information
Transmission Revenues		0	0	0	0
Sales to AEP Affiliates		0	0	0	0
Total Revenues		0	0	0	0
Interest Income		19.5	14	58	41.8
Interest Expense		19.3	13.9	57.6	41.6
Income Tax Expense		0	0	0.2	0
Equity Earnings in State Transcos		59.8	52.3	224	153
Net Income (Loss)		59.9	52.4	224.3	153
Balance Sheet Information
Total Property, Plant and Equipment		0		0		0
Accumulated Depreciation and Amortization		0		0		0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0		0		0
Notes Receivable, Related Parties		2,500		2,500		1,950
Total Assets		5,010.8		5,010.8		3,947.8
Total Long-term Debt Outstanding		2,574.4		2,574.4		1,950
AEP Transmission Co [Member] | Reconciling Adjustments [Member]
Reportable Segment Information
Transmission Revenues		0	0	0	0
Sales to AEP Affiliates		0.1	0	0	0
Total Revenues		0.1	0	0	0
Interest Income	[4]	(19.3)	(13.9)	(57.6)	(41.6)
Interest Expense	[4]	(19.3)	(13.9)	(57.6)	(41.6)
Income Tax Expense		0	0	0	0
Equity Earnings in State Transcos	[5]	(59.8)	(52.3)	(224)	(153)
Net Income (Loss)	[5]	(59.8)	$ (52.3)	(224)	$ (153)
Balance Sheet Information
Total Property, Plant and Equipment		0		0		0
Accumulated Depreciation and Amortization		0		0		0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		0		0		0
Notes Receivable, Related Parties	[6]	(2,500)		(2,500)		(1,950)
Total Assets	[7]	(4,917.1)		(4,917.1)		(3,935.5)
Total Long-term Debt Outstanding	[6]	$ (2,500)		$ (2,500)		$ (1,950)
[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.
[4]	Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
[5]	Elimination of AEPTCo Parent’s equity earnings in the State Transcos.
[6]	Elimination of intercompany debt.
[7]	Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Note Receivable from the State Transcos.

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			9 Months Ended			12 Months Ended
		Sep. 30, 2017USD ($)MMBTUMWhTgal		Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)MMBTUMWhTgal		Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)MMBTUMWhTgal
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 3.5			$ 3.5			$ 7.9
Cash Collateral Paid Netted Against Risk Management Liabilities		17			17			7.6
Fair Value of Derivative Instruments
Current Risk Management Assets		146.1			146.1			94.5
Long-term Risk Management Assets		310.4			310.4			289.1
Total Assets		456.5			456.5			383.6
Current Risk Management Liabilities		69.4			69.4			53.4
Long-term Risk Management Liabilities		352.7			352.7			316.2
Total Liabilities		422.1			422.1			369.6
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		26.6		$ 18.5	106.3		$ 62.3
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments		0.1		(1.1)	(0.1)		3
Gain (Loss) on Fair Value Portion of Long Term Debt		(0.1)		1.1	0.1		(3)
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		285.9			285.9			259.6
Amount of Cash Collateral Posted		2.5			2.5			0.4
Additional Settlement Liability if Cross Default Provision is Triggered		274.4			$ 274.4			235.8
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows					123 months
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.4			$ 0.4			0.5
Cash Collateral Paid Netted Against Risk Management Liabilities		0.3			0.3			0.7
Fair Value of Derivative Instruments
Current Risk Management Assets		30.3			30.3			2.6
Long-term Risk Management Assets		0.6			0.6			0
Current Risk Management Liabilities		0.9			0.9			0.3
Long-term Risk Management Liabilities		0.3			0.3			0.9
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		4.5		23.8	30.5		35.6
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0			0.1
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0			0
Indiana Michigan Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.3			0.3			0.3
Cash Collateral Paid Netted Against Risk Management Liabilities		0.1			0.1			0.4
Fair Value of Derivative Instruments
Current Risk Management Assets		11.6			11.6			3.5
Long-term Risk Management Assets		0.5			0.5			0
Current Risk Management Liabilities		2			2			0.3
Long-term Risk Management Liabilities		0.2			0.2			0.8
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2.1		8.4	21.1		23.7
Collateral Triggering Events [Abstract]
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0			0.1
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0			0
Ohio Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.1			0.1			0.2
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0			0
Fair Value of Derivative Instruments
Current Risk Management Assets		0.2			0.2			0.2
Current Risk Management Liabilities		7.6			7.6			5.9
Long-term Risk Management Liabilities		130.9			130.9			113.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(8.5)		(95.5)	(25.7)		(131.6)
Public Service Co Of Oklahoma [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			0.1
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0			0
Fair Value of Derivative Instruments
Current Risk Management Assets		4.7			4.7			0.8
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2.6		0.8	13.7		3.3
Southwestern Electric Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			0.1
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0			0
Fair Value of Derivative Instruments
Current Risk Management Assets		12.5			12.5			0.9
Long-term Risk Management Assets		0.7			0.7			0
Current Risk Management Liabilities		0.1			0.1			0.3
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		7.2		6.3	22.1		19.7
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[1]	448	[2]		448	[2]		372.4	[3]
Total Liabilities	[1]	340.8	[2]		340.8	[2]		321.5	[3]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	30.9			30.9			2.6
Total Liabilities	[1],[4]	1.2			1.2			1.2
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	12.1			12.1			3.5
Total Liabilities	[1],[4]	2.2			2.2			1.1
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	0.2			0.2			0.2
Total Liabilities	[1],[4]	138.5			138.5			119
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	4.7			4.7			0.8
Total Liabilities	[1],[4]	0			0
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[1],[4]	13.2			13.2			0.9
Total Liabilities	[1],[4]	0.1			0.1			0.3
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[5]	4.3			4.3			11.2
Hedging Liabilities	[5]	79.9			79.9			46.7
AOCI Gain (Loss) Net of Tax		(49.2)			(49.2)			(23.1)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(3.6)			4.3
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50			50			50
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	277.4			277.4			264.4
Long-term Risk Management Assets	[6]	348.1			348.1			315
Total Assets	[6]	625.5			625.5			579.4
Current Risk Management Liabilities	[6]	202.2			202.2			227.2
Long-term Risk Management Liabilities	[6]	329.6			329.6			301
Total Liabilities	[6]	531.8			531.8			528.2
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	93.7			93.7			51.2
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	50.4			50.4			22.7
Long-term Risk Management Assets	[6]	4.9			4.9			1.9
Total Assets	[6]	55.3			55.3			24.6
Current Risk Management Liabilities	[6]	20.7			20.7			20.6
Long-term Risk Management Liabilities	[6]	4.8			4.8			2.8
Total Liabilities	[6]	25.5			25.5			23.4
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	29.8			29.8			1.2
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	27.4			27.4			14.9
Long-term Risk Management Assets	[6]	3.3			3.3			1.1
Total Assets	[6]	30.7			30.7			16
Current Risk Management Liabilities	[6]	17.6			17.6			11.8
Long-term Risk Management Liabilities	[6]	3			3			1.9
Total Liabilities	[6]	20.6			20.6			13.7
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	10.1			10.1			2.3
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	0.3			0.3			0.4
Long-term Risk Management Assets	[6]	0			0			0
Total Assets	[6]	0.3			0.3			0.4
Current Risk Management Liabilities	[6]	7.6			7.6			5.9
Long-term Risk Management Liabilities	[6]	130.9			130.9			113.1
Total Liabilities	[6]	138.5			138.5			119
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	(138.2)			(138.2)			(118.6)
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	4.7			4.7			0.9
Long-term Risk Management Assets	[6]	0			0			0
Total Assets	[6]	4.7			4.7			0.9
Current Risk Management Liabilities	[6]	0			0			0
Long-term Risk Management Liabilities	[6]	0			0			0
Total Liabilities	[6]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	4.7			4.7			0.9
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	12.7			12.7			1.1
Long-term Risk Management Assets	[6]	0.7			0.7			0
Total Assets	[6]	13.4			13.4			1.1
Current Risk Management Liabilities	[6]	0.3			0.3			0.4
Long-term Risk Management Liabilities	[6]	0			0			0
Total Liabilities	[6]	0.3			0.3			0.4
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	13.1			13.1			0.7
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	8.1			8.1			13.2
Long-term Risk Management Assets	[6]	3.8			3.8			7.7
Total Assets	[6]	11.9			11.9			20.9
Current Risk Management Liabilities	[6]	13.5			13.5			6.3
Long-term Risk Management Liabilities	[6]	74			74			50.1
Total Liabilities	[6]	87.5			87.5			56.4
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	(75.6)			(75.6)			(35.5)
Interest Rate [Member]
Commodity:
Derivative, Notional Amount		1,000			1,000			500
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[5]	4.2			4.2			0
Hedging Liabilities	[5]	0			0			0
AOCI Gain (Loss) Net of Tax		(12.2)			(12.2)			(15.7)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(0.7)			(1)
Interest Rate [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		2.4			2.4			2.9
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0.7			0.7
Interest Rate [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(11)			(11)			(12)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1.3)			(1.3)
Interest Rate [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		2.2			2.2			3
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					1.1			1.1
Interest Rate [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		2.8			2.8			3.4
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0.8			0.8
Interest Rate [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(6.3)			(6.3)			(7.4)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1.4)			(1.4)
Interest Rate [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[6]	4.2			4.2			0
Long-term Risk Management Assets	[6]	0			0			0
Total Assets	[6]	4.2			4.2			0
Current Risk Management Liabilities	[6]	1.4			1.4			0
Long-term Risk Management Liabilities	[6]	0			0			1.4
Total Liabilities	[6]	1.4			1.4			1.4
Total MTM Derivative Contract Net Assets (Liabilities)	[6]	2.8			2.8			(1.4)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		289.7			289.7			277.6
Long-term Risk Management Assets		351.9			351.9			322.7
Total Assets		641.6			641.6			600.3
Current Risk Management Liabilities		217.1			217.1			233.5
Long-term Risk Management Liabilities		403.6			403.6			352.5
Total Liabilities		620.7			620.7			586
Total MTM Derivative Contract Net Assets (Liabilities)		20.9			20.9			14.3
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	(143.6)			(143.6)			(183.1)
Long-term Risk Management Assets	[7]	(41.5)			(41.5)			(33.6)
Total Assets	[7]	(185.1)			(185.1)			(216.7)
Current Risk Management Liabilities	[7]	(147.7)			(147.7)			(180.1)
Long-term Risk Management Liabilities	[7]	(50.9)			(50.9)			(36.3)
Total Liabilities	[7]	(198.6)			(198.6)			(216.4)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	13.5			13.5			(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	[7]	(20.1)			(20.1)			(20.1)
Long-term Risk Management Assets	[7]	(4.3)			(4.3)			(1.9)
Total Assets	[7]	(24.4)			(24.4)			(22)
Current Risk Management Liabilities	[7]	(19.8)			(19.8)			(20.3)
Long-term Risk Management Liabilities	[7]	(4.5)			(4.5)			(1.9)
Total Liabilities	[7]	(24.3)			(24.3)			(22.2)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(0.1)			(0.1)			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	[7]	(15.8)			(15.8)			(11.4)
Long-term Risk Management Assets	[7]	(2.8)			(2.8)			(1.1)
Total Assets	[7]	(18.6)			(18.6)			(12.5)
Current Risk Management Liabilities	[7]	(15.6)			(15.6)			(11.5)
Long-term Risk Management Liabilities	[7]	(2.8)			(2.8)			(1.1)
Total Liabilities	[7]	(18.4)			(18.4)			(12.6)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(0.2)			(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	[7]	(0.1)			(0.1)			(0.2)
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	(0.1)			(0.1)			(0.2)
Current Risk Management Liabilities	[7]	0			0			0
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(0.1)			(0.1)			(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	[7]	0			0			(0.1)
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	0			0			(0.1)
Current Risk Management Liabilities	[7]	0			0			0
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	0			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	[7]	(0.2)			(0.2)			(0.2)
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	(0.2)			(0.2)			(0.2)
Current Risk Management Liabilities	[7]	(0.2)			(0.2)			(0.1)
Long-term Risk Management Liabilities	[7]	0			0			0
Total Liabilities	[7]	(0.2)			(0.2)			(0.1)
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	0			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	[8]	146.1			146.1			94.5
Long-term Risk Management Assets	[8]	310.4			310.4			289.1
Total Assets	[8]	456.5			456.5			383.6
Current Risk Management Liabilities	[8]	69.4			69.4			53.4
Long-term Risk Management Liabilities	[8]	352.7			352.7			316.2
Total Liabilities	[8]	422.1			422.1			369.6
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	34.4			34.4			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	[8]	30.3			30.3			2.6
Long-term Risk Management Assets	[8]	0.6			0.6			0
Total Assets	[8]	30.9			30.9			2.6
Current Risk Management Liabilities	[8]	0.9			0.9			0.3
Long-term Risk Management Liabilities	[8]	0.3			0.3			0.9
Total Liabilities	[8]	1.2			1.2			1.2
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	29.7			29.7			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	[8]	11.6			11.6			3.5
Long-term Risk Management Assets	[8]	0.5			0.5			0
Total Assets	[8]	12.1			12.1			3.5
Current Risk Management Liabilities	[8]	2			2			0.3
Long-term Risk Management Liabilities	[8]	0.2			0.2			0.8
Total Liabilities	[8]	2.2			2.2			1.1
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	9.9			9.9			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	[8]	0.2			0.2			0.2
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	0.2			0.2			0.2
Current Risk Management Liabilities	[8]	7.6			7.6			5.9
Long-term Risk Management Liabilities	[8]	130.9			130.9			113.1
Total Liabilities	[8]	138.5			138.5			119
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(138.3)			(138.3)			(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	[8]	4.7			4.7			0.8
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	4.7			4.7			0.8
Current Risk Management Liabilities	[8]	0			0			0
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	4.7			4.7			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	[8]	12.5			12.5			0.9
Long-term Risk Management Assets	[8]	0.7			0.7			0
Total Assets	[8]	13.2			13.2			0.9
Current Risk Management Liabilities	[8]	0.1			0.1			0.3
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	0.1			0.1			0.3
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	$ 13.1			$ 13.1			$ 0.6
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		406			406			348
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		73.7			73.7			51.9
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		45.8			45.8			19.9
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		10.6			10.6			11.2
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		13.7			13.7			11.9
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		34.5			34.5			14.2
Coal [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.5			0.5			1.5
Coal [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.2			0.2			0.5
Coal [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.3			0.3			1
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		48.1			48.1			32.8
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		2			2			0
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		1.2			1.2			0
Natural Gas [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		18.3			18.3			0
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		7.9			7.9			7.4
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.5			1.5			1.4
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.7			0.7			0.7
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.8			1.8			1.6
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.8			0.8			0.8
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.9			0.9			0.9
Interest Rate Contract [Member]
Commodity:
Derivative, Notional Amount		$ 53.2			$ 53.2			$ 75.2
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0.1
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0.1
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			$ 0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.9		2.4	7		3.1
Vertically Integrated Utilities Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Vertically Integrated Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Transmission and Distribution Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0.1			0.1
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			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			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			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			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			0
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		17.7		9.2	38.5		50.1
Generation and Marketing Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.3		1	0.6		(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		0.6		1.2	6.3		3.7
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0.1	0		0.1
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.1)	0		(0.1)
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							2.1
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							5.8
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		1		1.5	4.9		4.9
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		0.3		0.8	1.6		2.7
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		0.2		0.1	0.5		0.2
Purchased Electricity for Resale [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.1		(0.4)	0.5		(1.3)
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	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	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		0.1		(0.1)	0.1		(0.3)
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	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	0		(0.2)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.1		(0.4)	0.4		(1.6)
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		0.1		(0.1)	0.1		(0.3)
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	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		0.1		(0.1)	0.1		(0.3)
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)	0		(0.2)
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)	0		(0.2)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[9]	(8.8)		(22.5)	(26.8)		(51)
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	[9]	0.1		5.2	0		(7.2)
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	[9]	(0.8)		1.6	(1)		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	[9]	(8.7)		(95.4)	(25.9)		(115.9)
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	[9]	0		0.1	0		0.4
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	[9]	0.3		2.8	0.1		5.5
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[9]	15.6		28.6	81.8		58
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	[9]	3.7		16.9	28.2		39.2
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	[9]	2.1		5.5	15.3		11.2
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	[9]	0		0	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	[9]	2.6		0.8	13.7		3.2
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	[9]	$ 7		$ 3.7	$ 22		$ 14.7
[1]	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.’’
[2]	The September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[3]	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 periods 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.
[4]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[5]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
[6]	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.”
[7]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[9]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 20,721.7		$ 20,721.7		$ 20,256.4
Long Term Debt, Fair Value		22,988.8		22,988.8
Other Temporary Investments
Cost		293.6		293.6		318.8
Gross Unrealized Gains		17.8		17.8		13.9
Gross Unrealized Losses		(0.7)		(0.7)		(1)
Fair Value		310.7		310.7		331.7
Debt and Equity Securities Within Other Temporary Investments
Proceeds from Investment Sales		0	$ 0	0	$ 0
Purchases of Investments		12.6	0.6	13.6	1.6
Gross Realized Gains on Investment Sales		0	0	0	0
Gross Realized Losses on Investment Sales		0	0	0	0
Nuclear Trust Fund Investments
Fair Value		2,433		2,433		2,256.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,433		2,433		2,256.2
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		22,988.8		22,988.8
Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				820.2		707.7
Other-Than-Temporary Impairments				(78.7)		(87.2)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		519.5	650	1,808.6	2,427
Purchases of Investments		525	656.5	1,842.2	2,452.9
Gross Realized Gains on Investment Sales		9.8	13.9	198.1	41.9
Gross Realized Losses on Investment Sales		5.2	6.5	145.4	22.2
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		403.6		403.6
After 1 year through 5 years		287.9		287.9
After 5 years through 10 years		184.2		184.2
After 10 years		167.6		167.6
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000		1,000		938
Adjusted Cost of Domestic Equity Securities		586		586		592
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
Includes Debt Included In Liabilities Held For Sale [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		20,721.7		20,721.7		20,391.2	[1]
Long Term Debt, Fair Value	[1]					22,211.9
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value	[1]					22,211.9
AEP Transmission Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,550		2,550		1,932
Long Term Debt, Fair Value		2,720.8		2,720.8		1,984.3
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,720.8		2,720.8		1,984.3
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,979.3		3,979.3		4,033.9
Long Term Debt, Fair Value		4,721.3		4,721.3		4,613.2
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		4,721.3		4,721.3		4,613.2
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,658.5		2,658.5		2,471.4
Long Term Debt, Fair Value		2,898.7		2,898.7		2,661.6
Nuclear Trust Fund Investments
Fair Value		2,433		2,433		2,256.2
Contractual Maturities, Fair Value of Debt Securities
Fair Value		2,433		2,433		2,256.2
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,898.7		2,898.7		2,661.6
Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				820.2		707.7
Other-Than-Temporary Impairments				(78.7)		(87.2)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		519.5	650	1,808.6	2,427
Purchases of Investments		525	656.5	1,842.2	2,452.9
Gross Realized Gains on Investment Sales		9.8	13.9	198.1	41.9
Gross Realized Losses on Investment Sales		5.2	$ 6.5	145.4	$ 22.2
Contractual Maturities, Fair Value of Debt Securities
Within 1 year		403.6		403.6
After 1 year through 5 years		287.9		287.9
After 5 years through 10 years		184.2		184.2
After 10 years		167.6		167.6
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		1,000		1,000		938
Adjusted Cost of Domestic Equity Securities		586		586		592
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,718.9		1,718.9		1,763.9
Long Term Debt, Fair Value		2,068.9		2,068.9		2,092.5
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,068.9		2,068.9		2,092.5
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,286.4		1,286.4		1,286
Long Term Debt, Fair Value		1,448		1,448		1,419
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		1,448		1,448		1,419
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,441.5		2,441.5		2,679.1
Long Term Debt, Fair Value		2,620.7		2,620.7		2,814.3
Fair Value Measurements (Textuals)
Long Term Debt, Fair Value		2,620.7		2,620.7		2,814.3
Cash [Member]
Other Temporary Investments
Cost	[2]	172.9		172.9		211.7
Gross Unrealized Gains	[2]	0		0		0
Gross Unrealized Losses	[2]	0		0		0
Fair Value	[2],[3]	172.9		172.9		211.7
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		1,043.3		1,043.3		967.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,043.3		1,043.3		967.4
Fixed Income Funds [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				37.1		29.8
Other-Than-Temporary Impairments				(3.3)		(7.6)
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		1,043.3		1,043.3		967.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		1,043.3		1,043.3		967.4
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				37.1		29.8
Other-Than-Temporary Impairments				(3.3)		(7.6)
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[4]	103.9		103.9		92.7
Gross Unrealized Gains	[4]	0		0		0
Gross Unrealized Losses	[4]	(0.7)		(0.7)		(1)
Fair Value	[4]	103.2		103.2		91.7
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,369.2		1,369.2		1,270.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,369.2		1,369.2		1,270.1
Domestic [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				783.1		677.9
Other-Than-Temporary Impairments				(75.4)		(79.6)
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[5]	1,369.2		1,369.2		1,270.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[5]	1,369.2		1,369.2		1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				783.1		677.9
Other-Than-Temporary Impairments				(75.4)		(79.6)
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		16.8		16.8		14.4
Gross Unrealized Gains		17.8		17.8		13.9
Gross Unrealized Losses		0		0		0
Fair Value	[5]	34.6		34.6		28.3
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	20.5		20.5		18.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[6]	20.5		20.5		18.7
Cash and Cash Equivalents [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				0		0
Other-Than-Temporary Impairments				0		0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	20.5		20.5		18.7
Contractual Maturities, Fair Value of Debt Securities
Fair Value	[6]	20.5		20.5		18.7
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				0		0
Other-Than-Temporary Impairments				0		0
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		974.3		974.3		785.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		974.3		974.3		785.4
US Government Agencies Debt Securities [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				32.6		27.1
Other-Than-Temporary Impairments				(1.9)		(5.5)
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		974.3		974.3		785.4
Contractual Maturities, Fair Value of Debt Securities
Fair Value		974.3		974.3		785.4
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				32.6		27.1
Other-Than-Temporary Impairments				(1.9)		(5.5)
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		60		60		60.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value		60		60		60.9
Corporate Debt [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				3.5		2.3
Other-Than-Temporary Impairments				(1.2)		(1.4)
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		60		60		60.9
Contractual Maturities, Fair Value of Debt Securities
Fair Value		60		60		60.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				3.5		2.3
Other-Than-Temporary Impairments				(1.2)		(1.4)
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		9		9		121.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		9		9		121.1
State and Local Jurisdiction [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				1		0.4
Other-Than-Temporary Impairments				(0.2)		(0.7)
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		9		9		121.1
Contractual Maturities, Fair Value of Debt Securities
Fair Value		$ 9		9		121.1
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Spent Nuclear Fuel and Decommissioning Trusts [Member]
Nuclear Trust Fund Investments
Gross Unrealized Gains				1		0.4
Other-Than-Temporary Impairments				$ (0.2)		$ (0.7)
[1]	Amounts include 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.
[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				9 Months Ended				12 Months Ended
		Sep. 30, 2017USD ($)$ / MMBTU$ / MWh		Sep. 30, 2016USD ($)		Sep. 30, 2017USD ($)$ / MMBTU$ / MWh		Sep. 30, 2016USD ($)		Dec. 31, 2016USD ($)$ / MWh
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 343.9				$ 343.9				$ 210.5
Other Temporary Investments		310.7				310.7				331.7
Risk Management Assets
Risk Management Assets		456.5				456.5				383.6
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,433				2,433				2,256.2
Total Assets		3,544.1				3,544.1				3,182
Liabilities, Fair Value Disclosure
Risk Management Liabilities		422.1				422.1				369.6
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		87.3		$ 149.3		2.5		$ 146.9		146.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	19.8		34.2		37.4		42.1
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	14.8		12.3		37.2		45.5
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		(24.3)		(34.4)		(29.5)		(16.7)
Settlements		(49.2)		(37.1)		(49.7)		(67.1)
Transfers into Level 3	[4],[5]	5.7		13.1		16.1		11.2
Transfers out of Level 3	[5]	(0.2)		(10)		(9.1)		1.1
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(9.3)		(29)		40.1		(64.6)
Ending Balance		45		98.4		$ 45		98.4		$ 2.5
Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]					0.10%				0.35%
High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]					5.39%				8.24%
Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]					2.04%				3.91%
Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	343.9				$ 343.9				$ 201.8
Other Temporary Investments		12.9				12.9				32.8
Risk Management Assets
Risk Management Assets		(167.5)				(167.5)				(213)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		6.5				6.5				11.4
Total Assets		195.8				195.8				33
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(181)				(181)				(212.7)
Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				8.7
Other Temporary Investments		296.4				296.4				293.8
Risk Management Assets
Risk Management Assets		1.2				1.2				6
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,383.2				1,383.2				1,277.4
Total Assets		1,680.8				1,680.8				1,585.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		3.2				3.2				8.2
Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Other Temporary Investments		1.4				1.4				5.1
Risk Management Assets
Risk Management Assets		321.2				321.2				396.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,043.3				1,043.3				967.4
Total Assets		1,365.9				1,365.9				1,369.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities		343.3				343.3				382.7
Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Other Temporary Investments		0				0				0
Risk Management Assets
Risk Management Assets		301.6				301.6				193.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Total Assets		301.6				301.6				193.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		256.6				256.6				191.4
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		(1)				(1)				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		23				23				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)				(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		3				3				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		77				77				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)				(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		16				16				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
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		(21)				(21)				(31)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8]	448	[9]			448	[9]			372.4	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	340.8	[9]			340.8	[9]			321.5	[10]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8]	(161.4)	[9]			(161.4)	[9]			(205.7)	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	(174.9)	[9]			(174.9)	[9]			(205.4)	[10]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8]	1.2	[9]			1.2	[9]			6	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	3.2	[9]			3.2	[9]			8.2	[10]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8]	307.9	[9]			307.9	[9]			379.9	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	306.6	[9]			306.6	[9]			352	[10]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8]	300.3	[9]			300.3	[9]			192.2	[10]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	205.9	[9]			205.9	[9]			166.7	[10]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		233.8				233.8				183.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 252.6				$ 252.6				$ 187.1
Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.05)				(0.05)				6.51
Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	92.77				92.77				86.59
Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	35.82				35.82				39.40
Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 0.9				$ 0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0				$ 0
Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[12]	2.47				2.47
Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[12]	3.03				3.03
Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[12]	2.68				2.68
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 66.9				$ 66.9				$ 10.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 4				$ 4				$ 4.3
FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(9.80)				(9.80)				(7.99)
FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	9.37				9.37				8.91
FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	0.32				0.32				0.86
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[8]	$ 4.3				$ 4.3				$ 11.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	79.9				79.9				46.7
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8]	(6.1)				(6.1)				(7.3)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	(6.1)				(6.1)				(7.3)
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	0				0				0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8]	9.1				9.1				16.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	35.3				35.3				29.3
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8]	1.3				1.3				1.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8]	50.7				50.7				24.7
Interest Rate and Foreign Currency [Member]
Risk Management Assets
Risk Management Assets		4.2				4.2
Interest Rate and Foreign Currency [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0				0
Interest Rate and Foreign Currency [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0				0
Interest Rate and Foreign Currency [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		4.2				4.2
Interest Rate and Foreign Currency [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0				0
Fair Value Hedges [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.4				1.4				1.4
Fair Value Hedges [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Fair Value Hedges [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Fair Value Hedges [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		1.4				1.4				1.4
Fair Value Hedges [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	8.4				8.4				15.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		39.3				39.3				18.5
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		41.3		(12.9)	[13]	1.4		11.7	[13]	11.7	[13]
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	6.2		22.7	[13]	17.2		25.5	[13]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0	[13]	0		0	[13]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	[13]	0		0	[13]
Settlements		(16.2)		(17.9)	[13]	(18.9)		(36.2)	[13]
Transfers into Level 3	[4],[5]	0		0.1	[13]	0		0	[13]
Transfers out of Level 3	[5]	0		0	[13]	0		0.1	[13]
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(1.9)		0.9	[13]	29.7		(8.2)	[13]
Ending Balance		29.4		(7.1)	[13]	29.4		(7.1)	[13]	1.4
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0.1				0.1				0.1
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(21.2)				(21.2)				(21.7)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	8.3				8.3				15.8
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		8.3				8.3				15.8
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		22.2				22.2				20.5
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Risk Management Assets
Risk Management Assets		30				30				3.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		30				30				3.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.6				0.6				2.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	30.9				30.9				2.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	1.2				1.2				1.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(21.3)				(21.3)				(21.8)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(21.2)				(21.2)				(22)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0				0
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	22.2				22.2				20.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	21.8				21.8				20.7
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	30				30				3.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.6				0.6				2.5
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1				1				0.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.4				$ 0.4				$ 0.4
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	14.85				14.85				19.68
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	45.72				45.72				48.55
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	33.99				33.99				36.34
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 29				$ 29				$ 3.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2				$ 0.2				$ 2.1
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	0.08				0.08				(0.23)
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	6.36				6.36				8.91
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	1.20				1.20				2.37
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,433				$ 2,433				$ 2,256.2
Total Assets		2,445.1				2,445.1				2,259.7
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		15.5		3.5	[13]	2.8		4.3	[13]	4.3	[13]
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	3.8		3.8	[13]	4		7	[13]
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0	[13]	0		0	[13]
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0	[13]	0		0	[13]
Settlements		(8.4)		(5)	[13]	(7.1)		(10.3)	[13]
Transfers into Level 3	[4],[5]	0		0	[13]	0		0	[13]
Transfers out of Level 3	[5]	0		0	[13]	0		0.1	[13]
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(0.7)		2.2	[13]	10.5		3.4	[13]
Ending Balance		10.2		4.5	[13]	10.2		4.5	[13]	2.8
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		6.5				6.5				11.4
Total Assets		(10.1)				(10.1)				(0.9)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,383.2				1,383.2				1,277.4
Total Assets		1,383.2				1,383.2				1,277.4
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,043.3				1,043.3				967.4
Total Assets		1,059.6				1,059.6				980.2
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		12.4				12.4				3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Total Assets		12.4				12.4				3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		2.2				2.2				0.2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	12.1				12.1				3.5
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	2.2				2.2				1.1
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(16.6)				(16.6)				(12.3)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(16.4)				(16.4)				(12.4)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0				0
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	16.3				16.3				12.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	16.4				16.4				13.3
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	12.4				12.4				3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	2.2				2.2				0.2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.6				0.6				0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.3				$ 0.3				$ 0.2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	14.85				14.85				19.68
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	45.72				45.72				48.55
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	33.99				33.99				36.34
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 11.8				$ 11.8				$ 2.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 1.9				$ 1.9				$ 0
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.02)				(0.02)				(7.90)
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	6.36				6.36				8.91
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	0.71				0.71				1.32
Ohio Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 15.6				$ 15.6				$ 27.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15.8				15.8				27.4
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(130.5)		(14.6)		(119)		15.9		15.9
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(0.1)		(0.1)		(1)		(1.8)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0		0
Settlements		1.2		0.9		5.1		4
Transfers into Level 3	[4],[5]	0		0		0		0
Transfers out of Level 3	[5]	0		0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(9.1)		(95.3)		(23.6)		(127.2)
Ending Balance		(138.5)		(109.1)		$ (138.5)		(109.1)		$ (119)
Ohio Power Co [Member] | Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]					0.10%				0.47%
Ohio Power Co [Member] | High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]					2.10%				3.40%
Ohio Power Co [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[7]					1.50%				2.72%
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				$ 0				$ 27.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(0.1)				(0.1)				27
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	15.6				15.6				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15.6				15.6				0
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.3				0.3				0.4
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Risk Management Assets
Risk Management Assets		0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		138.5				138.5				119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.2				0.2				0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	138.5				138.5				119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(0.1)				(0.1)				(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.3				0.3				0.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	138.5				138.5				119
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 138.5				$ 138.5				$ 119
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	22.89				22.89				30.14
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	61.48				61.48				71.85
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	41.21				41.21				47.45
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ 9.5		1.1		$ 0.7		0.6		$ 0.6
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	4		0.4		3.1		(1)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0		0
Settlements		(6.9)		(0.7)		(3.8)		0.4
Transfers into Level 3	[4],[5]	0		0		0		0
Transfers out of Level 3	[5]	0		0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(1.9)		0.3		4.7		1.1
Ending Balance		4.7		1.1		4.7		1.1		0.7
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	4.7				4.7				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(0.1)				(0.1)				(0.1)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(0.1)				(0.1)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	4.8				4.8				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.1				0.1
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		4.8				4.8				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0.1				$ 0
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(9.80)				(9.80)				(7.99)
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	1.03				1.03				1.03
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.69)				(0.69)				(0.36)
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 2.2				$ 2.2				$ 10.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15.4				15.4				11.2
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		12.4		1.4		0.7		0.8		0.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	3.8		4		6		7.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0		0
Settlements		(7.6)		(4.4)		(6.8)		(8.4)
Transfers into Level 3	[4],[5]	0		0		0		0
Transfers out of Level 3	[5]	0		0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	4.5		0.3		13.2		1.2
Ending Balance		13.1		$ 1.3		13.1		$ 1.3		0.7
Southwestern Electric Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	2.2				2.2				1.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		2				2				1.4
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				8.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0				0				8.7
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.1				0.1				0.3
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Risk Management Assets
Risk Management Assets		13.3				13.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		13.3				13.3				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.2				0.2
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	13.2				13.2				0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.1				0.1				0.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	(0.2)				(0.2)				(0.2)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	(0.2)				(0.2)				(0.1)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0				0				0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	0.1				0.1				0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.1				0.1				0.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[8],[14]	13.3				13.3				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[8],[14]	0.2				0.2				0.1
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.9				0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0				$ 0
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[12]	2.47				2.47
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[12]	3.03				3.03
Southwestern Electric Power Co [Member] | Natural Gas Contracts [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MMBTU	[12]	2.68				2.68
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 12.4				$ 12.4				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2				$ 0.2				$ 0.1
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Low [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(9.80)				(9.80)				(7.99)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | High [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	1.03				1.03				1.03
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Fair Value Significant Unobservable Input Price Per Unit | $ / MWh	[11]	(0.69)				(0.69)				(0.36)
Cash [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1],[15]	$ 172.9				$ 172.9				$ 211.7
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	12.9				12.9				32.8
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	158.6				158.6				173.8
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	1.4				1.4				5.1
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	0				0				0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,043.3				1,043.3				967.4
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,043.3				1,043.3				967.4
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,043.3				1,043.3				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				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,043.3				1,043.3				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				0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[16]	103.2				103.2				91.7
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0				0				0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		103.2				103.2				91.7
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0				0				0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0				0				0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[17]	34.6				34.6				28.3
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[17]	0				0				0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[17]	34.6				34.6				28.3
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[17]	0				0				0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[17]	0				0				0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	20.5				20.5				18.7
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	6.5				6.5				11.4
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	14				14				7.3
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0				0				0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0				0				0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	20.5				20.5				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	[18]	6.5				6.5				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	[18]	14				14				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	[18]	0				0				0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0				0				0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		974.3				974.3				785.4
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		974.3				974.3				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				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		974.3				974.3				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				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		974.3				974.3				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				0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60				60				60.9
Corporate Debt [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60				60				60.9
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60				60				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				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60				60				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				0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9				9				121.1
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9				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				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9				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				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		9				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				0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,369.2				1,369.2				1,270.1
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0				0				0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,369.2				1,369.2				1,270.1
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0				0				0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0				0				0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,369.2				1,369.2				1,270.1
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0				0				0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	1,369.2				1,369.2				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	[17]	0				0				0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	$ 0				$ 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]	Represents existing assets or liabilities that were previously categorized as Level 2.
[5]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[6]	Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable.
[7]	Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[8]	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.’’
[9]	The September 30, 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 periods 2018-2020; Level 2 matures $(1) million in 2017 and $3 million in periods 2018-2020 and $(1) million in periods 2021-2022; Level 3 matures $23 million in 2017, $77 million in periods 2018-2020, $16 million in periods 2021-2022 and $(21) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[10]	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 periods 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.
[11]	Represents market prices in dollars per MWh.
[12]	Represents market prices in dollars per MMBtu.
[13]	Includes both affiliated and nonaffiliated transactions.
[14]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[15]	Primarily represents amounts held for the repayment of debt.
[16]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[17]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[18]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	33.00%	40.40%	35.30%	(195.60%)
Income Taxes (Textuals) [Abstract]
Pre July 1 2017 Illinois Corporate Income Tax Rate			5.25%
Effective July 1 2017 Illinois Corporate Income Tax Rate			7.00%
Illinois Replacement Tax			2.50%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate			7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate			9.50%
2011 Audit Issue Settlement [Member]
Valuation Allowance			$ 56
Certain Assets Held for Sale and 2015 Federal Income Tax Return [Member]
Valuation Allowance	$ 66		$ 66
AEP Transmission Co [Member]
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	33.50%	33.50%	33.80%	32.60%
Appalachian Power Co [Member]
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	33.40%	36.10%	35.50%	36.20%
Income Taxes (Textuals) [Abstract]
Pre July 1 2017 Illinois Corporate Income Tax Rate			5.25%
Effective July 1 2017 Illinois Corporate Income Tax Rate			7.00%
Illinois Replacement Tax			2.50%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate			7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate			9.50%
Indiana Michigan Power Co [Member]
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	30.60%	31.80%	30.10%	29.50%
Income Taxes (Textuals) [Abstract]
Pre July 1 2017 Illinois Corporate Income Tax Rate			5.25%
Effective July 1 2017 Illinois Corporate Income Tax Rate			7.00%
Illinois Replacement Tax			2.50%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate			7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate			9.50%
Ohio Power Co [Member]
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	36.90%	31.70%	35.60%	33.40%
Income Taxes (Textuals) [Abstract]
Pre July 1 2017 Illinois Corporate Income Tax Rate			5.25%
Effective July 1 2017 Illinois Corporate Income Tax Rate			7.00%
Illinois Replacement Tax			2.50%
Pre July 1, 2017 Total Illinois Corporate Income Tax Rate			7.75%
Effective July 1, 2017 Total Illinois Corporate Income Tax Rate			9.50%
Public Service Co Of Oklahoma [Member]
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	37.20%	37.70%	37.40%	36.80%
Southwestern Electric Power Co [Member]
Federal Statutory Tax Rate			35.00%
Effective Income Tax Rate	21.20%	28.90%	25.70%	26.70%
Income Taxes (Textuals) [Abstract]
Effect On Effective Tax Rate Due To Increase/Decrease In Income Tax Expense	$ 10

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
		Oct. 26, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Long-term Debt
Senior Unsecured Notes			$ 16,038.6		$ 16,038.6
Pollution Control Bonds			1,612.4		1,612.4		$ 1,725.1
Notes Payable			224.5		224.5		326.9
Securitization Bonds			1,449.4		1,449.4		1,705
Spent Nuclear Fuel Obligation	[1]		267.9		267.9		266.3
Other Long-term Debt			1,128.9		1,128.9		1,606.9
Total Long-term Debt Outstanding			20,721.7		20,721.7		20,256.4
Long-term Debt Due Within One Year			2,359.3		2,359.3		2,878
Long-term Debt			18,362.4		18,362.4		17,378.4
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				2,771.1
Retirements and Principal Payments					2,427.2	$ 1,307.6
Short-term Debt:
Securitized Debt for Receivables	[3]		750		750		673
Commercial Paper			295		295		1,040
Notes Payable			14.3		14.3		0
Total Short-term Debt			$ 1,059.3		$ 1,059.3		$ 1,713
Securitized Debt for Receivables	[3],[4]		1.17%		1.17%		0.70%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable			1.33%	0.73%	1.17%	0.65%
Net Uncollectible Accounts Receivable Written Off			$ 7	$ 7.7	$ 18.2	$ 17.5
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts			939.8		939.8		$ 945
Total Principal Outstanding			750		750		673
Delinquent Securitized Accounts Receivable			44.3		44.3		42.7
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable			27.8		27.8		27.7
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable			264.2		264.2		322.1
Financing Activities (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			311		311		311
Repayments of Long-term Debt					2,427.2	$ 1,307.6
Reacquired Pollution Controls Bonds Held by Trustees			728		$ 728
Maximum Percentage Debt to Capitalization					67.50%
Total Commitment from Bank Conduits to Finance Receivables			750		$ 750
Includes Debt Included In Liabilities Held For Sale [Member]
Long-term Debt
Senior Unsecured Notes							14,761
Total Long-term Debt Outstanding			$ 20,721.7		$ 20,721.7		$ 20,391.2	[5]
Commercial Paper [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		1.39%		1.39%		1.02%
Loans Payable [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		2.88%		2.88%		0.00%
AEP Subsidiaries [Member]
Long-term Debt
Long-term Debt Due Within One Year			$ 393.7		$ 393.7		$ 427.5
Long-term Debt			1,421.5		1,421.5		1,737.5
AEP Transmission Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			2,550		2,550		1,932
Long-term Debt			2,550		2,550		1,932
Financing Activities (Textuals) [Abstract]
Sub-Limit of Secured Debt			$ 50		$ 50
Maximum Percentage of Consolidated Tangible Net Assets			10.00%		10.00%
Maximum Percentage Debt to Capitalization					67.50%
AEP Transmission Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					$ 467.2
Maximum Loans to Money Pool					194.8
Average Borrowings from Money Pool					235.7
Average Loans to Money Pool					19.3
Net Loans (Borrowings) to/from Money Pool			$ 162.9		162.9
Authorized Short Term Borrowing Limit	[6]				$ 795
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
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					1.36%	0.82%
Average Interest Rate For Funds Loaned					1.04%	0.74%
AEP Transmission Co [Member] | Direct Borrowing [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					$ 1.1
Maximum Loans to Money Pool					151.9
Average Borrowings from Money Pool					1.1
Average Loans to Money Pool					38.9
Borrowings from Parent			0.9		0.9
Loans to Parent			$ 96.1		96.1
Authorized Short Term Borrowing Limit					$ 75
Maximum and Minimum Interest Rates
Maximum Interest Rate for Funds Borrowed					1.49%	0.91%
Minimum Interest Rate For Funds Borrowed					0.92%	0.69%
Maximum Interest Rate For Funds Loaned					1.49%	0.91%
Minimum Interest Rate for Funds Loaned					0.92%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed					1.27%	0.80%
Average Interest Rate For Funds Loaned					1.31%	0.81%
AEP Transmission Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 125
Interest Rate (Percentage)			3.10%		3.10%
Due Date					2,026
AEP Transmission Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 500
Interest Rate (Percentage)			3.75%		3.75%
Due Date					2,047
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,979.3		$ 3,979.3		4,033.9
Long-term Debt Due Within One Year			149.2		149.2		503.1
Long-term Debt			3,830.1		3,830.1		3,530.8
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					377.9	$ 213.6
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			116.9		116.9		142
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.5	1.6	4.2	5.4
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			335.5	361.7	1,029.4	1,071.6
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					377.9	$ 213.6
Reacquired Pollution Controls Bonds Held by Trustees			104		$ 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					$ 231.5
Maximum Loans to Money Pool					160.7
Average Borrowings from Money Pool					152.2
Average Loans to Money Pool					32.2
Net Loans (Borrowings) to/from Money Pool			$ (45.9)		(45.9)
Authorized Short Term Borrowing Limit					$ 600
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
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					1.24%	0.78%
Average Interest Rate For Funds Loaned					1.28%	0.79%
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
Appalachian Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 23.5
Interest Rate (Percentage)			2.008%		2.008%
Due Date					2,024
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 23.5
Appalachian Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 325
Interest Rate (Percentage)			3.30%		3.30%
Due Date					2,027
Appalachian Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 250
Interest Rate (Percentage)			5.00%		5.00%
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 250
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,658.5		2,658.5		2,471.4
Long-term Debt Due Within One Year			462.1		462.1		209.3
Long-term Debt			2,196.4		2,196.4		2,262.1
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					227.1	$ 76.8
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			132.7		132.7		136.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.8	2	4.9	5.6
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			409.9	448	1,218.9	1,220.2
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					227.1	$ 76.8
Reacquired Pollution Controls Bonds Held by Trustees			50		$ 50
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					$ 367.4
Maximum Loans to Money Pool					12.6
Average Borrowings from Money Pool					205.7
Average Loans to Money Pool					12.6
Net Loans (Borrowings) to/from Money Pool			$ (164.9)		(164.9)
Authorized Short Term Borrowing Limit					$ 500
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
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					1.24%	0.73%
Average Interest Rate For Funds Loaned					1.27%	0.78%
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 4.9
Interest Rate (Variable)					Variable
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 4.9
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 22.3
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 22.3
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 23.6
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 23.6
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 23.9
Interest Rate (Variable)					Variable
Due Date					2,020
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 23.9
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 24.3
Interest Rate (Variable)					Variable
Due Date					2,021
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 24.3
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables Six [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		1
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 1.1
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,025
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 1.1
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
Indiana Michigan Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 40
Interest Rate (Percentage)			2.05%		2.05%
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
Issuances	[2]				$ 52
Interest Rate (Variable)					Variable
Due Date					2,021
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
Indiana Michigan Power Co [Member] | Pollution Control Bonds Five [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
Indiana Michigan Power Co [Member] | Pollution Control Bonds Six [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 50
Interest Rate (Variable)					Variable
Due Date					2,025
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 50
Indiana Michigan Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 300
Interest Rate (Percentage)			3.75%		3.75%
Due Date					2,047
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,718.9		$ 1,718.9		1,763.9
Long-term Debt Due Within One Year			397		397		46.4
Long-term Debt			1,321.9		1,321.9		1,717.5
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					46.4	$ 395.9
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			356.3		356.3		388.3
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			6.1	8.1	16.5	23.4
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			616.3	750.9	1,741.7	2,011.2
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					46.4	$ 395.9
Reacquired Pollution Controls Bonds Held by Trustees			345		345
Ohio Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					280.6
Maximum Loans to Money Pool					56.2
Average Borrowings from Money Pool					141
Average Loans to Money Pool					27.9
Net Loans (Borrowings) to/from Money Pool			$ (167.6)		(167.6)
Authorized Short Term Borrowing Limit					$ 400
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
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					1.40%	0.85%
Average Interest Rate For Funds Loaned					0.98%	0.74%
Ohio Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.1
Interest Rate (Percentage)			1.149%		1.149%
Due Date					2,028
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.1
Ohio Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 16.2
Interest Rate (Percentage)			0.958%		0.958%
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 16.2
Ohio Power Co [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 22.5
Interest Rate (Percentage)			0.958%		0.958%
Due Date					2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 22.5
Ohio Power Co [Member] | Securitization Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 7.6
Interest Rate (Percentage)			2.049%		2.049%
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 7.6
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,286.4		1,286.4		1,286
Long-term Debt Due Within One Year			0.5		0.5		0.5
Long-term Debt			1,285.9		1,285.9		1,285.5
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					0.3	$ 150.3
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			143.4		143.4		110.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2	1.8	5.2	4.7
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			407	390.6	1,022.6	971.9
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.3	$ 150.3
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					$ 185.2
Maximum Loans to Money Pool					0
Average Borrowings from Money Pool					121.3
Average Loans to Money Pool					0
Net Loans (Borrowings) to/from Money Pool			$ (118)		(118)
Authorized Short Term Borrowing Limit					$ 300
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
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					1.30%	0.76%
Average Interest Rate For Funds Loaned					0.00%	0.81%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.3
Interest Rate (Percentage)			3.00%		3.00%
Due Date					2,027
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.3
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,441.5		2,441.5		2,679.1
Long-term Debt Due Within One Year			385.4		385.4		353.7
Long-term Debt			2,056.1		2,056.1		2,325.4
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					353.6	$ 3.3
Short-term Debt:
Notes Payable			14.3		14.3		0
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			167.1		167.1		$ 130.9
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2	2.1	5.4	5.3
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			455	$ 460.4	1,200.8	1,183.9
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 353.6	$ 3.3
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					109.6
Average Loans to Money Pool					169.5
Net Loans (Borrowings) to/from Money Pool			(48.3)		(48.3)
Authorized Short Term Borrowing Limit					$ 350
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
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					1.26%	0.79%
Average Interest Rate For Funds Loaned					0.98%	0.91%
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 Money Pool			$ 2		$ 2
Maximum and Minimum Interest Rates
Maximum Interest Rate					1.49%	0.91%
Minimum Interest Rate					0.00%	0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Loaned					1.27%	0.79%
Southwestern Electric Power Co [Member] | Notes Payable, Other Payables [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 3.3
Interest Rate (Percentage)			4.58%		4.58%
Due Date					2,032
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 3.3
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 115
Interest Rate (Variable)					Variable
Due Date					2,020
Southwestern Electric Power Co [Member] | Other Long Term Debt Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 100
Interest Rate (Variable)					Variable
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 100
Southwestern Electric Power Co [Member] | Other Long Term Debt Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.2
Interest Rate (Percentage)			3.50%		3.50%
Due Date					2,023
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.2
Southwestern Electric Power Co [Member] | Other Long Term Debt Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.1
Interest Rate (Percentage)			4.28%		4.28%
Due Date					2,023
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.1
Southwestern Electric Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 250
Interest Rate (Percentage)			5.55%		5.55%
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 250
Southwestern Electric Power Co [Member] | Loans Payable [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		2.88%		2.88%		0.00%
AEP Texas [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 60
Interest Rate (Percentage)			1.75%		1.75%
Due Date					2,020
AEP Texas [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 400
Interest Rate (Percentage)			2.40%		2.40%
Due Date					2,022
AEP Texas [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 300
Interest Rate (Percentage)			3.80%		3.80%
Due Date					2,047
AEP Generating Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 152.7
Interest Rate (Percentage)			6.33%		6.33%
Due Date					2,037
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 152.7
AEP Texas Central Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 60
Interest Rate (Percentage)			5.20%		5.20%
Due Date					2,030
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 60
AEP Texas Central Co [Member] | Pollution Control Bonds Two [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 41
Interest Rate (Percentage)		5.625%
Due Date		2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 41
AEP Texas Central Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 27.2
Interest Rate (Percentage)			0.88%		0.88%
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 27.2
AEP Texas Central Co [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 161.2
Interest Rate (Percentage)			5.17%		5.17%
Due Date					2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 161.2
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
Kentucky Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 65
Interest Rate (Percentage)			2.00%		2.00%
Due Date					2,020
Kentucky Power Co [Member] | Pollution Control Bonds Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 65
Interest Rate (Variable)					Variable
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 65
Kentucky Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 65
Interest Rate (Percentage)			3.13%		3.13%
Due Date					2,024
Kentucky Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 40
Interest Rate (Percentage)			3.35%		3.35%
Due Date					2,027
Kentucky Power Co [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 165
Interest Rate (Percentage)			3.45%		3.45%
Due Date					2,029
Kentucky Power Co [Member] | Senior Unsecured Notes Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 55
Interest Rate (Percentage)			4.12%		4.12%
Due Date					2,047
Kentucky Power Co [Member] | Senior Unsecured Notes Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 325
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 325
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
Transource Missouri [Member] | Other Long Term Debt Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 130.8
Interest Rate (Variable)					Variable
Due Date					2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 130.8
Transource Energy [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 132.1
Interest Rate (Variable)					Variable
Due Date					2,020
Includes Debt Included In Liabilities Held For Sale [Member]
Long-term Debt
Total Long-term Debt Outstanding	[1]						$ 20,391.2
Long-term Debt Due Within One Year	[1]						3,013.4
Long-term Debt	[1]						$ 17,377.8
[1]	Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
[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]	Amounts include 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.
[6]	Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.